September/October Reservoir 2018

"The Best of" Issue

In This Issue...

Evaluation of Elk Point Basin Evaporites for Solution Mining and Basin Modelling Uncertainty in Geomechanics and Induced Seismicity Technical Evaluation of the Carbon/Oxygen logs Run in Blocks V and VI of the Lamar Field in the Maracaibo Lake Basin, Venezuela

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Emma MacPherson, Communications Coordinator, Canadian Society of Petroleum Geologists Tel: 403-513-1230, emma.macpherson@cspg.org

The RESERVOIR is published 6 times per year by the Canadian Society of Petroleum Geologists. The purpose of the RESERVOIR is to publicize the Society’s many activities and to promote the geosciences. We look for both technical and non-technical material to publish.

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While reasonable care has been taken, authors and the CSPG make no guarantees that any of the equations, schematics, or devices discussed will perform as expected or that they will give the desired results. Some information contained herein may be inaccurate or may vary from standard measurements. The CSPG expressly disclaims any and all liability for the acts, omissions, or conduct of any third-party user of information contained in this publication. Under no circumstances shall the CSPG and its officers, directors, employees, and agents be liable for any injury, loss, damage, or expense arising in any manner whatsoever from the acts, omissions, or conduct of any third-party user.

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TABLE OF CONTENTS

SEPTEMBER/OCTOBER 2018 – VOLUME 45, ISSUE 5

MONTHLY SPONSORS...............................................................................................4 MESSAGE FROM THE EDITORS..............................................................................6 MESSAGE FROM THE BOARD ................................................................................7 THE BEST OF EDITION A Sedimentological, Ichnological, and Architectural Comparison of Estuarine and Fluvial Outcrops Using Uav-Based Outcrop Modelling in the Lower Cretaceous Mcmurray Formation............................................................................8 FRONT COVER Entrenched Meander – Colorado River.

Horseshoe Bend is located just outside Page, northern Arizona. Here a meander of the Colorado River has incised up to 300 m into the Early Jurassic Navajo Sandstone.

Tectonic uplift began in this region during the Late Cretaceous. The Navajo Sandstone was deposited as giant, aeolian sand dunes.

Photo: Jon Noad

Evaluation of Elk Point Basin Evaporites for Solution Mining and Basin Modelling.......................................................................................................16 Imaging Technology Breakthroughs Make the Analysis of Fine-Grain Rocks More Routine; With Examples From the Oilsands................................................19 Uncertainty in Geomechanics and Induced Seismicity.......................................22 Technical Evaluation of the Carbon/Oxygen logs Run in Blocks V and VI of the Lamar Field in the Maracaibo Lake Basin, Venezuela. ..............................27

UPCOMING EVENTS Technical Luncheon................................................................................................32 Division Talks...........................................................................................................35

SOCIETY NEWS Stanley Slipper Medal Call for Nominations.........................................................45 CSPG Rock Analysis Workshop..............................................................................46 2018 Ph.D. and M.Sc. Call for Theses.....................................................................47

RESERVOIR ISSUE 5 • SEPTEMBER/OCTOBER 2018

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"THE BEST OF" EDITION

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Jason Frank Technical Editor for the CSPG Reservoir Sr. Geologist at Athabasca Oil Corporation Jason Frank is a Professional Geologist who holds a B.Sc. and M.Sc. from the University of Alberta.

He has over 16 years of experience in oil and gas including technical and leadership positions in exploration and development both on and offshore. Past experience includes Shell Canada Ltd., Burlington Resources Ltd., ConocoPhillips Canada Ltd., and Talisman Energy Inc. Jason has volunteered for the Society in the past, most recently chairing the Duvernay session at the Society’s annual convention (2014) and the Honourary Address Committee.

e often think of “the best" in terms of a sporting event or a race, where participants are ranked on how well they performed during a given task. Finish the race first, and the gold medal is yours. In this edition of the Reservoir, we’ve asked GeoConvention attendees what they thought were the best of the past GeoConvention, and invited those authours to present their work in paper format. This is the second time we’ve invited “the best” to showcase some of their work, and we hope you enjoy it. A complete list of winners is printed on page 31.

utility of machine learning and artificial intelligence in conjunction with high resolution photographs, short wave infrared scanners, and X Ray Fluorescence to aid in the interpretation of core data from heavy oil reservoirs.

Derek Hayes and his co-authours present amazingly detailed outcrop images taken

by UAV (unmanned aerial vehicle) of the McMurray Formation. In conjunction with their observational data at the outcrop scale, the authours are able to generate high-resolution 3D outcrop models that aid in their interpretations. The paper presents the readers with a set of criterial for discerning fluvial and estuarine facies within the McMurray Formation.

Rafael Becerra Delmoral presents a petrophysical logging technique that can be utilized to measure actual oil saturations within cased-hole logs.

Utilizing Carbon/Oxygen logging, his case study presents findings within the Lamar Field in the Lake Maracaibo Basin of Venezuela, where this technique was used, and results are presented.

Elaine Lord and Nicholas Harris present their work on the Elk Point Basin evaporites, and how they relate to solution mining and basin modelling. To this end their study aims to better understand salt distribution and facies variability to aid in predicting where suitable localities may exist for future energy storage sites.

Travis Hobbs Technical Editor for the Reservoir Professional Geologist at Encana Travis Hobbs is an undergraduate from University of Calgary with a graduates degree from Simon Fraser University in Geology. Professionally he has worked both domestically and internationally for 19 years in the Oil & Gas industry, and is currently celebrating 15 years with Encana.

Industry roles have included development, exploration, management and business development. Prior to the Reservoir, Travis has held previous roles on convention committees and six years as the Chair of Continuing Education. As free time permits Travis enjoys cycling, cross-country skiing and teaching his two daughters violin.

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Sandon and Stancliffe have teamed up to present imaging breakthroughs that are making the analysis of fine-grained rocks more routine. They present the

Scott McKean uses “the statistics we tried to avoid in school” and presents an interesting look at uncertainty analysis in geomechanics and induced seismicity. He summarizes data from both the Montney Formation at Kakwa, and Duvernay Formation at Kaybob.

Lastly, we wanted to remind you of the “Geology in your Neighbourhood” contest from the last “GeoFun” edition. We’ve had a few submissions, but wanted to make sure that you all get a chance to take a look at photos, and submit your answers. We will be posting answers in the next edition.

Thanks again for your support of the Reservoir.

Your editors, Jason and Travis

RESERVOIR ISSUE 5 • SEPTEMBER/OCTOBER 2018

MESSAGE FROM THE BOARD

MESSAGE FROM THE BOARD

By MIchael Webb, Director

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elcome back from summer vacation and welcome to this new edition of the CSPG Reservoir. I hope many of you had the chance to visit some of Canada’s geologic wonders this past summer, and share them with family and friends. My two teenage sons are constantly amazed (or more truthfully embarrassed) at my ability to blather on about reservoir and source rocks, mountain building events, structural traps, and other topics whenever we are on a holiday hike. Despite this, I know that sharing the learnings of geoscience as applied within the energy industry is a valuable contribution of the CSPG, and we do this through the Society’s various Outreach activities.

The 2018 Student Industry Field Trip was highlighted in last month’s Reservoir in an article written by outgoing co-chairs Jesse Schoengut and Vanessa Huey. SIFT is one of our top outreach activities, giving undergraduate students from across Canada a chance to experience life as an oil and gas geologist. This year’s SIFT was a huge success and I’d like to thank Jesse and Vanessa, along with the numerous

volunteers who support the SIFT program, for doing a great job reaching out to these students across the country. The incoming SIFT co-chairs are Nicole Hunter and Colin Etienne, so please reach out and offer your volunteer hours to help them put on a great SIFT program next year.

The University Outreach committee is responsible for reaching students across Canada with the key messages of the CSPG. Among other events, lecture tours are a large part of our efforts to reach students across Canada, and I’d like to thank the outgoing committee chair Sonia Brar and her committee volunteers for arranging strong technical lecture tours that were appreciated by the students. The incoming chair is Carson Brown, and he’d be happy to hear from CSPG members with your encouragement and ideas.

Our CSPG Outreach portfolio is broader still. Did you know we have a Distinguished Lecturer Program, where we ask a former Link Award winner (or other respected speaker) to travel to various universities to give their technical luncheon talk? Andrew Fox has been heading up this committee

for a few years now, and is always looking for Canadian university venues for a great Distinguished Lecturer.

In addition, our Ambassador program has been very successful over the past few years, meeting with university professors and administrators to see how the CSPG could help impact their geoscience curriculum.

The countless hours of volunteer time from ambassadors Colin Yeo, Brad Hayes, and Ian McIlreath have helped the CSPG focus our outreach efforts across the country.

The Outreach portfolio also includes GeoWomen, led by co-chairs Jocelyn Keith-Asante and Mandy Williams, which helps women embark in a career in the geosciences.

I hope I’ve helped shine some light on our Outreach portfolio in this short note. In addition, thanks are due to the CSPG office staff who support the various outreach committees and events. The next time you are near the offices, please drop in to say hi and thank our office staff for doing a great job. Finally, I’d like to acknowledge the tremendous support of the CSPG Foundation, which provides funding for much of the CSPG’s outreach activities.

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TECHNICAL ARTICLE

A SEDIMENTOLOGICAL, ICHNOLOGICAL, AND ARCHITECTURAL COMPARISON OF ESTUARINE AND FLUVIAL OUTCROPS USING UAVBASED OUTCROP MODELLING IN THE LOWER CRETACEOUS MCMURRAY FORMATION Derek A. Hayes1, Michael J. Ranger2, Eric R. Timmer1 and Murray K. Gingras1 1 Ichnology Research Group (IRG), Department of Earth and Atmospheric Sciences, University of Alberta 2 Ranger Petroleum Consulting dahayes@ualberta.ca INTRODUCTION The lower Cretaceous McMurray Formation is the primary reservoir unit for the Athabasca oil sands, and therefore has been the subject of numerous studies over the past century. Arguably, the modern era of research began with the work of Flach and Mossop in the early 1980’s. Their work at the Steepbank River outcrops established that the ubiquitous epsilon cross-strata (later classified as "Inclined Heterolithic Stratification" or IHS) formed as fluviallyderived laterally accreted point-bar deposits overlying thickly-bedded cross-bedded sand, interpreted as basal dune deposits of the same channel (Mossop and Flach, 1983; Flach and Mossop, 1985). Around the same time, Pemberton et al. (1982) suggested that the ichnological assemblage in the IHS at the Steepbank outcrops was representative of deposition in brackish-water settings.

In the years following these initial studies, mounting evidence such as the recognition of a significant tidal influence (Smith, 1987; Smith, 1988) and continued ichnological studies (Ranger and Pemberton, 1992) led to the acceptance of an estuary depositional model for the cross-bedded sand and IHS in the middle McMurray Formation.

More recently, the acquisition of detailed three-dimensional seismic volumes in the McMurray has uncovered widespread meander belts exhibiting point-bars on a similar scale to those found in the modern Mississippi River (Smith et al., 2009; Hubbard et al., 2011; Labrecque et al., 2011; Durkin, 2016; Blum, 2017). In plan-view, seismic data show highly migratory point-

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Figure 1: Location map indicating the location of the three studied outcrops. The Amphitheatre outcrop is adjacent to Fort MacKay, located along the MacKay river in Twp 94 R 11W4 (57° 11' 34.30" N, 111° 39' 50.09" W). The Steepbank #3A outcrop is north of Fort McMurray, located along the Steepbank River in Twp 92 R 09W4 (57° 01' 0.75" N, 111° 26' 2.19" W).The Crooked Rapids outcrop is southwest of Fort McMurray along the Athabasca River, located in Twp 87-88 R 12W4 (56° 35' 38.98" N, 111° 52' 6.57" W). bars with high width to thickness ratios that suggest deposition in the upper backwater reaches of a river based on modern analogues. As a result, the fluvial vs estuary

debate was renewed, with detrital zircon work (e.g. Blum and Pecha, 2014; Benyon et al., 2016) and geomorphology (e.g. Durkin et al., 2017) cited as the main arguments

RESERVOIR ISSUE 5 • SEPTEMBER/OCTOBER 2018

TECHNICAL ARTICLE

Figure 2: Orthomosaic of the Amphitheatre outcrop showing the stratigraphic relationship and spatial distribution of the two interpreted architectural elements.

The basal cross-bedded sand unit is interpreted to be a middle estuary compound dune complex that is incised into by an inner estuary IHS-filled channel.The rose diagrams outline the architectural differences between the strata. Black petals represent master bedding orientation and red petals are palaeo-flow data.

There is an architectural change from forward accreting compound dunes to laterally and vertically accreting IHS as evidenced by the rose diagrams. for a fluvially-dominated (albeit tidally influenced) depositional model.

The purpose of this paper is to discuss the facies and facies architectures of three lithologically similar (i.e. a basal crossbedded sand unit overlain by an IHS unit), but depositionally dissimilar outcrops.

Based on sedimentological, ichnological, and architectural observations, the crossbedded sand and IHS units at each outcrop are separated into individual large-scale architectural elements interpreted to have been deposited in different physiographic locations along a fluvial to estuarine depositional system.

Differentiating between these architectural elements can be difficult, particularly in core. For example, a cross-bedded sand unit may be interpreted as fluvial channel dunes, estuarine channel dunes, or estuarine compound dunes. Likewise, IHS can form in fluvial or estuarine environments.

As such, this study identifies the key differences between fluvial and estuarine facies in the McMurray Formation.

STUDY AREA AND METHODS The outcrops included in this study are the Amphitheatre (Twp 94, R 11 W4), Steepbank #3A (representing all of the Steepbank #3 outcrops; Twp. 92, R 09 W4), and Crooked Rapids (Twp 87-88, R 12 W4) outcrops (Fig. 1). The characterization of

RESERVOIR ISSUE 5 • SEPTEMBER/OCTOBER 2018

these outcrops is achieved by using threedimensional photogrammetry techniques and an unmanned aerial vehicle (UAV, or drone) to generate high-resolution 3D outcrop models to collect dense bed orientation datasets for analysis. These data are combined with sedimentological and ichnological data acquired from logging the outcrops in the field. Of note, the palaeocurrent data collected at the Steepbank #3 outcrops are from the appendix sections of Jablonski (2012). For a more detailed methodology, particularly regarding the collection of orientation data from 3D outcrops, readers are directed to Hayes et al. (in press).

ESTUARINE OUTCROPS Amphitheatre Outcrop The Amphitheatre outcrop is characterized by two main geobodies: a basal, 15 metre thick planar-tabular and trough crossbedded sand unit, and an overlying 8 metre thick IHS-dominated unit which truncates the cross-bedded sand unit with a significant scour visible on the northeast side of the outcrop (Fig. 2).

The cross-bedded sand at the Amphitheatre outcrop is medium-grained and thinly- to thickly-bedded (0.1-2 metres) with sand beds thinning upwards. Sedimentary features common in tidal depositional environments, such as metre-scale current

reversals and reactivation surfaces, are observed. Bioturbation in this unit is sporadic and unevenly distributed, but bioturbation index can range from 1-3 with Cylindrichnus and rare Siphonichnus composing the ichnological assemblage.

Of note, this low-diversity ichnological assemblage is consistent with deposition in a brackish-water environment. Accretionary bedding surfaces are gently dipping (commonly less than 5°) and oriented in three directions: northeast, southeast, and southwest (Fig. 2). Palaeocurrent orientations show a dominant northeastsouthwest trend, with a subordinate southeast trend. Notably, the low dip of master bedding surfaces and the tendency for sediment transport to be parallel to master bedding accretion is characteristic of compound dune deposits (Allen, 1980; Dalrymple, 2010). Based on: 1) evidence for metre-scale sedimentary structures commonly found in tidal environments; 2) a low diversity ichnological assemblage consistent with the brackish-water ichnological model; and 3) orientation data conforming to forward accreting bedforms, the sand at Amphitheatre is interpreted to be a compound dune complex in a middle estuary setting.

The overlying IHS-filled channel contains (Continued on page 10...)

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TECHNICAL ARTICLE (Continued from page 9...) energy conditions, possibly related to seasonal discharge variations of a river.

These observations, combined with the lack of an ichnological signature and the lack of a discernable tidal influence, suggest that the cross-bedded sand unit at Steepbank may be ascribed to the deposition of simple dunes at the base of a fluvial channel.

Figure 3: Orthomosaic of the Steepbank #3A outcrop showing the stratigraphic relationship and spatial distribution of the cross-bedded sand and IHS units.The basal cross-bedded sand is interpreted as simple fluvial dunes. These dunes are abruptly overlain by laterally-accreting estuarine IHS. The rose diagrams depict the architectural differences among the preserved strata at the Steepbank #3 outcrops, with master bedding data in black petals and paleocurrent data in red petals. As evidenced by the rose diagrams, there is a clear change in bedding architecture between the fluvial dunes and estuarine IHS, with the fluvial dunes having no preferred accretionary growth direction while the estuarine IHS accretes toward the northeast. a coalified log near the channel base. The channel fill conforms to the shape of the scour, with IHS beds having apparent dip from 3-9°. The IHS is composed of interbedded fine- to very fine- sand and silt beds, with bedding typically on a centimetre to decimetre scale. Bioturbation index ranges from 1-4. Trace fossils in this unit include Cylindrichnus, Planolites, and Gyrolithes, which represents a common ichnological assemblage in muddominated IHS in the McMurray Formation (Shchepetkina et al., 2016a; Gingras et al., 2016). Bed orientation data is consistently dipping toward the southeast, while palaeocurrent data is orthogonal to the master bedding surfaces, although it shows a bimodal trend in flow direction (Fig. 2).

Based on these observations, the IHS unit at Amphitheatre is best interpreted as a brackish-water inner estuary channel fill succession that shows both lateral accretion (master bedding and palaeocurrent data are oriented orthogonal to each other) and vertical accretion (IHS conforms to the shape of the scour, appearing to be concave-upward) tendencies. Given that the presence of Cylindrichnus, a burrow formed by a marine polycheate, provides indirect evidence for a tidal influence on the IHS, it is plausible that the bimodal

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trend in flow direction oriented northeastsouthwest is the result of tides in the channel during deposition.

Steepbank #3A Outcrop An interpreted orthomosaic of the middle McMurray is shown in Figure 3. For the purposes of this study, only the middle McMurray strata will be discussed at Steepbank. The Steepbank #3A outcrop is characterized by two main architectural geobodies: a basal, 8-10 metre thick, medium-grained planar tabular and trough cross-bedded sand unit sharply overlain by a 20 metre thick IHS succession consisting of pervasively bioturbated fine- to very fine-grained sand and mud couplets.

The cross-bedded sand is thickly bedded, typically between 0.2-2 metres thick, and completely devoid of bioturbation. Thin interbeds of decimetre-scale dunes with mud clasts preserved on the dune toesets are observed locally. Master bedding surfaces are steeply dipping (typically above 8°) and show no preferred accretion direction while palaeocurrent data (from Jablonski, 2012) indicates flow direction is toward the northwest (Fig. 3). As evidenced by the range in cross-bed thickness, the sand was likely deposited under varying

The overlying IHS is sedimentologically, ichnologically, and architecturally distinct from the cross-bedded sand. It is characterized by thinly-bedded (2-20 centimetre) fine- to very fine-grained sand interbedded with mud. Within the sand beds, sharp-based current ripples and planartabular bedding are common. Bioturbation index throughout the IHS varies from 1-4. Both sand and mud beds contain Cylindrichnus, Skolithos, and Planolites.

The collected IHS bedding orientations and palaeocurrent data, courtesy of Jablonski (2012), show an average deviation of 77° suggesting an orthogonal relationship between accretionary growth direction and flow direction (Fig. 3). Based on: 1) a discontinuity to the underlying fluvial dunes; 2) bedsets that thin and muddy upwards; and 3) an increase in bioturbation upwards, the IHS unit at Steepbank is interpreted to be a laterally-accreting estuarine point-bar deposit. Importantly, all of these characteristics are consistent with vertical sections of laterally accreting point-bars in tidally influenced brackishwater settings (Smith, 1987; Gingras et al., 1999; MacEachern et al., 2010).

Discussion of Estuarine Facies and Facies Architectures In estuarine cross-bedded sand (i.e. the compound dune complex at the Amphitheatre outcrop), the presence of metre-scale flow reversals and reactivation surfaces coupled with a low-diversity brackish-water ichnological assemblage point toward deposition in a tidallydominated estuary environment (Fig. 4A). Architecturally, middle estuary dunes display a dominant trend of forward accretion related to the dominant flood- and ebb-tide orientation in the estuary (NE-SW in this study) (Fig. 2 rose diagrams). A subordinate master bedding trend oriented orthogonal to the dominant flood-ebb tide oriented dunes is apparent (SE in this study), with these smaller dunes forming as a result of flowing water in the

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TECHNICAL ARTICLE

Figure 4: Plate illustrating common sedimentary structures, bioturbation, and stratigraphic relationships between cross-bedded sand and IHS at outcrops interpreted to be estuarine. A) Metre-scale flow reversal with arrows indicating the palaeoflow direction based on the orientation of the cross-beds. Amphitheatre outcrop, compound dune complex. B) Pervasively bioturbated IHS consisting of a low-diversity, high intensity assemblage of Cylindrichnus (Cy) and Skolithos (Sk).

Steepbank #3A outcrop, IHS unit. C) Close-up of the scoured contact separating the compound dune complex and the overlying IHS. Amphitheatre outcrop. D) The sharp contact between fluvial dune sand and the overlying estuarine IHS. Steepbank #3A outcrop. troughs of large-scale dunes during low tide (Dalrymple, 1984b). The interpreted compound dunes in the McMurray are similar architecturally and in scale to those at Cobequid Bay in the Bay of Fundy (Dalrymple, 1984a; Dalrymple, 1984b) despite the McMurray being a mesotidal setting (Smith, 1987) in contrast to the modern macrotidal regime at Cobequid Bay. By far the most characteristic feature in estuarine IHS is the presence of an ichnological assemblage that is diagnostic of deposition in brackishwater (Fig. 4B). Because stressful living conditions for organisms are common in brackish-water environments (e.g. resulting from fluctuations in salinity or high sedimentation rates), a number of predictable trends in bioturbation are manifested in estuarine deposits. Gingras et al. (2016) provide a comprehensive review of brackish-water bioturbation, but in general estuarine strata will contain a low-diversity, locally high intensity suite of diminutive, marine-derived, infaunal trophic generalists (e.g. Cylindrichnus, Skolithos, Planolites, and monospecific

RESERVOIR ISSUE 5 • SEPTEMBER/OCTOBER 2018

Gyrolithes – all of which are common in estuarine IHS in the McMurray Formation).

At Amphitheatre and Steepbank, both sand and mud lithosomes are bioturbated, suggesting more gradual sediment accumulation in an estuary channel when compared to the seasonal discharge of a fluvial channel. On top of the pervasive bioturbation, estuarine IHS is considerably more heterolithic than fluvial IHS – this results from the propensity for mud flocculation in estuarine environments as a result of the mixing of fresh and salt water.

size is apparent in addition to pervasively bioturbated IHS overlying sparsely bioturbated (Amphitheatre) estuarine sand or unbioturbated (Steepbank #3) fluvial sand. The sedimentological, ichnological, and architectural differences between the cross-bedded strata and overlying IHS at these outcrops is compelling evidence that the contacts between the units at both outcrop locations are disconformable, and therefore may represent important stratigraphic surfaces within the McMurray Formation (Ranger and Gingras, 2008).

Stratigraphically, the contact between crossbedded dune sand and IHS at the estuarine outcrops suggest they are two genetically separate units. At the Amphitheatre outcrop, an inner estuary laterally accreting IHSfilled channel incises into a middle estuary forward accreting compound dune deposit, resulting in a disconformity (Fig. 4C).

Similarly, we recognize an abrupt contact at all Steepbank #3 outcrops (Steepbank #3A-C), with no evidence for interfingering or grading, between the fluvial dune sand and inner estuary laterally accreting IHS (Hayes et al., in press) (Fig. 4D). Above these contacts, an abrupt decrease in grain

FLUVIAL OUTCROP Crooked Rapids At the Crooked Rapids outcrop, one kilometre of continuously exposed strata provide extensive depositional strike and dip views of large-scale architectural units.

Similar to the aforementioned estuarine outcrops, the Crooked Rapids outcrop is characterized by two main architectural elements: a basal 13 metre thick, finegrained, trough to low-angle planar tabular cross-bedded and planar-bedded sand overlain by a 13 metre thick IHS unit. In contrast to the Amphitheatre and Steepbank (Continued on page 12...)

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TECHNICAL ARTICLE (Continued from page 11...)

Figure 5: Image of the Crooked Rapids outcrop showing the stratigraphic relationship between cross-bedded dune sand and IHS. Here, the cross-bedded sand climbs up the point-bar surface and grades laterally into IHS toward the top of the bar. This results in an interfingering relationship between the cross-bedded sand and IHS, which suggests they are elements of the same architectural unit.The rose diagrams show that the point-bar accretes toward the southwest. outcrops, the contact between the crossbedded sand and the IHS at Crooked Rapids is observed to both interfinger laterally and grade vertically. In effect, the cross-bedded sand unit constitutes a lower sand-dominated component of the IHS architecture. Due to the scale of the Crooked Rapids outcrop (the outcrop is over a kilometre wide), this paper will focus only on the lateral transition from sand-dominated to IHS-dominated strata, interpreted to represent a single fluvial point-bar (Fig. 5).

In the cross-bedded sand unit, bed thickness may be upward of 1.5 metres, but typically range from 0.5-1 metre thick (Fig. 6A). Trough cross-beds are common closer to the base of the unit, and grade upward into planar tabular cross-beds, planar beds, and current rippled sand, representing a decrease in energy upward consistent with fluvial point-bar facies models (Allen, 1970). Along the entire extent of the outcrop, organic detritus commonly drape the foresets of the dunes and are deposited in the dune bottomsets (Fig. 6B). Within massively appearing sand, coal fragments up to 2 centimetres wide are scattered throughout (Fig. 6C). Internal erosional surfaces between successive sand beds are common, and are interpreted as truncated lateral accretion surfaces following the freshet flooding phase in the channel. Orientation data show a

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consistent dip direction toward the westsouthwest for at least 500 metres laterally, with master bedding surfaces dipping between 4-10° and, as will be shown, the master bedding is the basal component of an IHS architecture. Based on the abundance of high-energy indicators such as amalgamated lateral accretion surfaces and the scale of cross-bedding, this unit, which is devoid of bioturbation, is likely the lower part of a fluvial point-bar.

The overlying IHS at Crooked Rapids is sedimentologically and architecturally similar to the cross-bedded sand unit.

The IHS consists of inclined, interbedded fine-grained sand and organic-rich silt.

Ichnologically, the IHS conforms to studies of modern point-bars in the fluvial reaches of estuaries - bioturbation is extremely rare, and is limited to surface traces that have a low preservation potential in the rock record (Shchepetkina et al., 2016b). The IHS sand beds are current rippled and typically between 20-60 centimetres thick, which is noticeably thicker than sandy IHS beds at Amphitheatre and Steepbank (Fig. 6D).

Furthermore, the IHS sand beds gradually thicken downdip until the silt beds of the IHS couplets are occluded. Throughout the IHS, similar to the underlying crossbedded sand, organic detritus is abundant.

IHS bedding dips typically between 8-16° toward the southwest, roughly the same direction as the cross-bedded sand below

(Fig. 5 rose diagrams).

Together, the cross-bedded sand and IHS are sedimentologically and ichnologically consistent with fluvial point-bars: they are devoid of bioturbation and sedimentary structures that commonly indicate the presence of tides (e.g. large-scale flow reversals, reactivation surfaces, double mud drapes, etc.) while containing a significant amount of organic matter and coal fragments. Importantly, these two units are observed to interfinger with one another over 50-100 metres laterally, demonstrating a gradational facies architecture (Fig. 6E).

As such, based on the sedimentology and architectural similarities (both units accrete toward the southwest), the crossbedded dune sand and overlying IHS are taken together to represent the lower and upper parts of a single fluvial point-bar at the Crooked Rapids outcrop.

Discussion of Fluvial Facies and Facies Architecture In the McMurray Formation, Crooked Rapids is the only outcrop that shows widespread evidence for fluvial deposition on a large scale. Because the crossbedded sand and IHS units at the Crooked Rapids outcrop are sedimentologically, ichnologically, and architecturally similar, the entire outcrop will be discussed as a whole.

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Vertical sections through the channelized architectural unit at the Crooked Rapids outcrop show that sedimentologically, the strata conform to fluvial facies models (Allen, 1970). Specifically, the upward transition from trough cross-beds to planar bedding and ripple cross-lamination suggest a decrease in energy level up the point-bar resulting from a shallower water depth. The presence of abundant organics and coal fragments throughout the outcrop, although not unequivocal evidence of fluvial deposition, still point toward a higher riverine influence than what is interpreted at the estuarine outcrops (Fig. 6B-C). When coupled with the lack of sedimentary structures common in tidallydominated depositional environments and the lack of bioturbation, these observations point toward a deposition in a fluvial environment.

Figure 6: Plate illustrating common sedimentary structures and the stratigraphic relationship between cross-bedded sand and IHS in the fluvial Crooked Rapids outcrop. A) Metre-scale cross-bedded dune sand.

B) Decimetre- to metre-scale cross-bedded dune sand with abundant organic detritus in the bottomsets of the dunes. C) Coal fragments in massively-appearing sand. D) Expression of fluvial IHS in outcrop. E) The interfingering relationship between cross-bedded sand and IHS.

Fluvially-dominated IHS typically results from two-stage sedimentation: 1) sand beds are deposited, usually as bedload during phases of high river discharge during seasonal freshet flooding events; and 2) organic-rich mud beds are deposited as suspended load during waning flow conditions during times of lower fluvial discharge (Sisulak and Dashtgard, 2012). As a result, the sand beds of fluvial IHS (representing the freshet) are characteristically thicker than estuarine IHS, where the tidal prism in addition to fluvial discharge moves the turbidity

Figure 7: Idealized vertical sections of estuarine and fluvial point-bar strata. All core photos shown are 7cm wide. A) Vertical estuarine point-bar succession after Smith (1987) and MacEachern et al. (2010). Sandy lateral accretion beds are characteristically thinner than fluvial lateral accretion deposits, and muddy strata is abundant throughout the bar. Bioturbation is dominated by a low-diversity assemblage in the channel (BI of 1-3) with an increase in BI upward. Core photos are from the 16-21-95-11W4 core. B) Vertical fluvial point-bar model after Allen (1970). Modified from Donselaar and Overeem (2008). Note the abundance of sand in lateral accretion deposits, as well as the lack of bioturbation and fining-upward trend. Bioturbation in overbank deposits may be variable, but consists of meniscate traces created by insects. Core photos are from the 13-22-95-11W4 well.

(Continued on page 14...)

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TECHNICAL ARTICLE (Continued from page 13...) maximum, which dictates where sand and mud will be deposited in the system (Ranger and Pemberton, 1992; Lettley et al., 2005). Since fluvial IHS is controlled mainly by high-energy river floods, often times the silty waning-flow deposit is eroded by the succeeding freshet phase, resulting in the amalgamation of sand beds and the lack of silty or muddy strata. This contrasts with estuarine IHS, where the deposition of sand and mud occurs more gradually, as evidenced by the occurrence of bioturbation in both sand and mud lithosomes (Gingras et al., 2016).

The lack of bioturbation in the Crooked Rapids outcrop is similar to what has been observed in the fluvial reaches of modern estuaries (Hauck et al., 2009; La Croix et al., 2015; Shchepetkina et al., 2016b; Shchepetkina et al., 2016c). Work by these authors has shown that in freshwater channels landward of brackish-water incursion, bioturbation is rare and most commonly absent on subtidal and intertidal point-bars. In fact, colonization below the water line in continental environments is rare (Hasiotis, 2002; Gingras et al., 2016).

Consequently, much of the bioturbation in fluvial environments typically occurs either on the channel margins or in overbank environments (as opposed to in the channel), where insects produce meniscate ichnogenera such as Taenidium, Scoyenia, Beaconites, and Naktodemasis (Gingras et al., 2016).

From an architectural point of view, the observed relationship between the cross-bedded sand and IHS at Crooked Rapids is significantly different from the contacts observed at the Amphitheatre and Steepbank outcrops. Most notably, at the Crooked Rapids outcrop, the two units are observed to interfinger over tens to hundreds of metres laterally (Fig. 6E).

They are in effect elements of the same architectural unit. The nature of this contact results in cross-bedded sand climbing up the point-bar and grading laterally into IHS toward the top of the bar. This observation is crucial – when coupled with consistently southwestward accreting bedding data in both the cross-bedded sand and IHS units, the interfingering relationship provides unequivocal evidence that together they are genetically related, and therefore are deposited on the same fluvial point-bar.

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SUMMARY Considering the recent re-emergence of the debate on whether middle McMurray Formation strata is dominantly estuarine or fluvial, this study discusses the key sedimentological, ichnological, and architectural differences between deposits found in brackish versus fresh water in outcropping McMurray strata. There are several notable differences in the facies and facies architectures between estuarine and fluvial deposits in the McMurray Formation, which are summarized below (and in Figure 7, which is a schematic comparison of estuarine and fluvial laterally-accreting point-bar strata).

Outcropping strata ascribed to deposition in estuarine depositional environments in the McMurray Formation are characterized by (Fig. 7A): 1) The presence of sedimentary structures common in tidally-dominated environments (e.g. metre-scale flow reversals and reactivation surfaces).

2) Inclined heterolithic stratification consisting of thin current-rippled sand beds (2-20 centimetres) interbedded with muddy strata – both sand and mud lithosomes are pervasively bioturbated.

3) An ichnological assemblage that consists of a low-diversity, locally high intensity suite of diminutive, marine-derived, infaunal trophic generalists (Pemberton et al., 1982; Gingras et al., 2016).

4) Inclined heterolithic stratification that conforms to estuarine lithofacies models – bedsets thin and muddy upward, while bioturbation intensity increases upwards (Smith, 1987; MacEachern et al., 2010).

5) Ichnological assemblages that include Cylindrichnus or Gyrolithes, since the presence of either ichnogenera act as an indirect tidal indicator considering that the tracemakers are marine polychaetes that must be advected into an estuary by tides.

6) A sharp, locally incising contact in outcrop at the base of the IHS, implying that it and the underlying cross-bedded dune sand are not genetically related.

7) Abrupt changes in bedding architecture (i.e. forward vs. lateral accretion), grain size, and bioturbation intensity across the aforementioned contact.

In contrast, outcropping strata interpreted to represent fluvial deposition is characterized by (Fig. 7B): 1) The lack of discernable sedimentological evidence for tidal modulation.

2) An abundance of terrestrial organic detritus and coalified debris.

3) Event-driven deposition on the pointbar, as indicated by the abundance of truncated lateral accretion surfaces related to larger seasonal flooding events.

4) Inclined heterolithic stratification consisting of sand beds up to 60 centimetres thick interbedded with thin organic-rich silt – neither lithosome is bioturbated.

5) The lack of bioturbation in both crossbedded dune sand and IHS units – this conforms to studies on the fluvial reaches of modern estuaries.

6) Cross-bedded sand deposits climbing up the surface of the bar, grading laterally into IHS in the upper point-bar strata.

7) A gradual contact showing an interfingering relationship between the cross-bedded sand and IHS, implying the two units are genetically related to each other.

8) No change in bedding architecture (i.e. both units laterally accrete toward the southwest) or grain size across the aforementioned contact.

The results of this study provide some clarity into the debate regarding the depositional origin of McMurray Formation strata. As evidenced by the three outcrops presented in this study, fluvial and estuarine deposits do coexist in the McMurray Formation.

Importantly, in both fresh- and brackishwater deposits, there is a predictable distribution of facies that conform to either fluvial or estuarine lithofacies models. Therefore, the recognition of

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sedimentological and ichnological features pertaining to either interpretation outlined in this paper can be applied to core datasets to supplement (or, in some cases, hinder) interpretations based off seismic volumes and detrital zircon work. In a nutshell, this work shows that fluvial and estuarine deposits in the McMurray can be differentiated with relative ease, at least in

outcrop, since the facies models for these depositional environments show markedly different defining features.

Cenovus Energy, Nexen Energy, and Woodside Energy generously provided funding for this project.

ACKNOWLEDGEMENTS

REFERENCES

A Natural Sciences and Engineering Research Council of Canada (NSERC) Discovery Grant to MKG helped fund this research. BP Canada, Husky Canada,

Full List of References available on the CSPG website

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EVALUATION OF ELK POINT BASIN EVAPORITES FOR SOLUTION MINING AND BASIN MODELLING Elaine L. Lord1, Nicholas B. Harris1 Department of Earth and Atmospheric Sciences, University of Alberta, Edmonton, Alberta, Canada T6G 2E3

1

Introduction The Lotsberg and Prairie Evaporite salts of the Middle to Upper Devonian Elk Point Group (EPG) were deposited landward of the Presqu’Ile Barrier in the Alberta Basin, which is subdivided into the Central Alberta sub-basin (CAB) and North Alberta sub-basin (NAB; Fig. 1). Parts of the CAB preserve the entire evaporite depositional sequence of the EPG (Fig. 1). The NAB does not contain Lotsberg evaporites and is not the focus of this study. Previous studies have estimated salt thicknesses of EPG evaporites in the CAB and NAB (Grobe 2000; Hauk et al. 2017).

Figure 1 Map of Alberta with the approximate boundary between the Northern Alberta Basin (NAB) and Central Alberta Basin (CAB) indicated by a dashed line.Yellow-shaded field is the extent of the Prairie Evaporite Formation and the orange-shaded field is the extent of the Lotsberg Formation. Studied drill cores are highlighted with black stars and well logs with black circles.

The purple star indicates well UWI: 100/07-17056-21W4/00. Cross-sections AA’ and BB’ are labelled. Grey regions were emergent Devonian topography

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Salt is soluble, impermeable, and selfannealing, making it ideal for the development of caverns for energy storage (Mortazavi and Nasab 2017; Mannan et al. 2014). One specific application is compressed air energy storage (CAES), which is particularly applicable to renewable energy sources that have variable energy outputs.

nature of EPG salt deposits and predict where salt caverns are best developed. To this end we map evaporite cycles in the CAB for halite thickness, potash and insoluble bulk percent, as well as insoluble interbed thickness, continuity, and lateral extent within the salt formations, to be subdivided into facies to assist in salt characterization by paleoenvironmental interpretation.

To successfully mine a salt cavern, geologic understanding is necessary to avoid cavern collapse, winging, or mining of unsuitable salt beds (e.g., under minimum thickness; Kunstman et al. 2007). Our objective is to use facies modelling to determine the

Dataset We examined six drills cores and 320 well logs from the CAB that intersect the Prairie Evaporite and Lotsberg salts (Fig. 1). Petrel is used to map well log data, which are cross validated by logging formation thickness,

Figure 2 Unit thickness isopach maps for the Prairie Evaporite Formation (A) and the Lotsberg Formation (B) in the Central Alberta Basin (CAB), with 25 m interval spacing. The Muskeg Formation is coeval to the Prairie Evaporite Formation.The Meadow Lake Escarpment is emergent topography for the Lotsberg Formation. Sharp outer edges are an artifact of the picked Petrel boundary

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lithology, and halite purity from drill core.

Results Distribution of the Lotsberg Formation in our study area conforms to Early Devonian emergent topographic features, such as the Meadow Lake Escarpment to the east (Van Hees 1958) and the surface of the sub-Devonian unconformity (Burrowes and Krause 1987; Moore 1988; Figs. 1, 2, 4).

The Prairie Evaporite Formation is more extensive than the Lotsberg Formation in the study area (Fig. 2) and pinches out to the west, where it interfingers with the coeval near-shore Muskeg Formation, which consists largely of anhydrite, carbonate, and minor halite. The EPG deposits dip to the south west in the CAB. Figure 3 Correlated well log (left) and our interpreted core log (right) for the Lotsberg Formation in well UWI: 100/07-17-05621W4/00. Core location is noted with a purple star in Figure 1. Depth is true vertical depth.

We define six evaporite cycles throughout the Prairie Evaporite Formation and four in the Lotsberg Formation (Fig. 3), marked by increasing concentrations of potash minerals and insoluble sediments upward in each cycle that can be correlated with gamma ray and density logs.

Discussion The depositional extent (Fig. 2) and dip (Fig. 4B) of the Prairie Evaporite and Lotsberg Formations modeled from well logs are comparable to findings of previous studies (Grobe 2000; Rogers 2017). Both formations meet or exceed the minimum thickness required for safe salt cavern creation (≥ 100 m) and do not exceed the maximum burial depth of 2000 m (Kunstman et al. 2007).

Both formations are shallowest in eastern Alberta (Fig. 4), and therefore more suited to economic development.

Figure 4 Depth cross-sections of the Prairie Evaporite and Lotsberg Formations along the AA’ and BB’ lines indicated in Figure 1. and their respective facies cycles, each cycle is represented by a different color. Cross-sections are presented with 100x vertical exaggeration. Cycle colors are equivalent to Figure 4

We subdivide salt beds into stratigraphic cycles, within which depositional facies are interpreted based on the relative abundances of halite, potash, clays, anhydrite, and carbonates. We interpret the beginning of each cycle as lagoon facies (halite with disseminated clays, anhydrite, and carbonates) overlain by salt pan facies (halite with potash minerals, and more anhydrite than carbonates), Warren 2006; Jackson and Hudec 2017. The transition from lagoon to salt pan facies within the cycles indicates deposition in standing water within a peri-continental inland sea under normal evaporative conditions (Kendall 1978). Thick interbeds of insoluble minerals were deposited at the beginning

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of lagoon conditions when the basin was flooded by fresh seawater.These insoluble interbeds act as seals during solution mining, restricting salt solution below the interbed; they can also collapse as salt is mined from under the bed, potentially destabilizing the side walls of the cavern resulting in structural instability. Tracing each cycle allows us to accurately estimate thick interbed depths.

Conclusions Within our study area, the Prairie Evaporite Formation is thickest and shallowest in eastern Alberta, making it suitable for cavern development. The Lotsberg Formation was deposited less extensively over the basin, and is abruptly truncated by the Meadow Lake Escarpment to the south west. However, near its depositional center, the Lotsberg Formation has lower volumes of insoluble components, making it a more predictable unit for development.

Acknowledgements We thank Tyler Hauck, Matt Grobe, Chris Schneider, and Tim Lowenstein for their input. We also thank the Core Research Center, Plains Midstream Canada, Imperial Oil, and Newalta for kindly allowing us access to cores. This study is supported by grants from Alberta Innovates, NSERC CRD, Rocky Mountain Power, and Compass Minerals.

References Burrowes, O. and F. Krause 1987. Overview of the Devonian system: subsurface of Western Canada Basin: SPG Special Publications, Devonian Lithofacies and Reservoir Styles in Alberta, 13th CSPG Core Conference and Display, p. 1-20.

Grobe, M., 2000. Distribution and thickness of salt within the Devonian Elk Point group, western Canada sedimentary basin: Earth Sciences Report, v. 2, p. 1-12.

Hauck, T., J. T. P., Hathaway, B., Grobe, M., and MacCormack, K., 2017. New insights from regional-scale mapping and modelling of the Paleozoic succession in northeast Alberta: Paleogeography, evaporite dissolution, and controls on Cretaceous depositional patterns on the sub-Cretaceous unconformity: Bulletin of Canadian Petroleum Geology, v. 65, no. 1, (Continued on page 18...)

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TECHNICAL ARTICLE (Continued from page 17...) p. 87-114.

Jackson, M. P., and Hudec, M. R., 2017.

Salt tectonics: Principles and practice, Cambridge University Press.

Kendall, A. C., 1978. Facies models 12.

Subaqueous evaporites: Geoscience Canada, v. 5, no. 3.

Kunstman, A., Poborska-Mlynarska, K., Urbancyzk, K., 2007. SOLUTION MINING IN SALT DEPOSITS: Outline of recent development trends, AGH University of Science and Technology Press.

Mannan, P., Baden, G., Olein, L., Brandon,

C., Scorfield, B., Naini, N., and Cheng, J., 2014. Techno-economics of energy storage: Alberta Innovates-Technology Futures, p.

3-11.

Moore, P. F. 1988. Devonian geohistory of the western interior of Canada: CSPG Special Publications, Proceedings of the 2nd International Symposium on the Devonian System, Memoir 14, Volume I: Regional Syntheses, p. 67-83.

Mortazavi, A., and Nasab, H., 2017. Analysis of the behavior of large underground oil storage caverns in salt rock: International Journal for Numerical and Analytical Methods in Geomechanics, v. 41, no. 4, p.

602-624.

Rogers, M. B., 2017. Stratigraphy of the Middle Devonian Keg River and Prairie Evaporite formations, northeast Alberta, Canada: Bulletin of Canadian Petroleum Geology, v. 65, no. 1, p. 5-63.

Van Hees, H., The Meadow Lake Escarpment-Its Regional Significance to Lower Palaeozoic Stratigraphy1958.

Williston Basin Symposium.

Warren, J. K., 2006, Evaporites: sediments, resources and hydrocarbons, Springer Science & Business Media.

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IMAGING TECHNOLOGY BREAKTHROUGHS MAKE THE ANALYSIS OF FINE-GRAIN ROCKS MORE ROUTINE; WITH EXAMPLES FROM THE OILSANDS G. Sandon, and R.P.W. Stancliffe | Enersoft Inc., Calgary, Canada INTRODUCTION Sandstones are always described in core and chip samples more thoroughly than mudstones and siltstones. This is primarily due to oil and gas being more easily produced from the sandstones and the inability to image the fine sediments easily.

Furthermore, collecting the information created large databases which were difficult to collate and only resolved the properties of a small sample set. With the introduction of new technologies into rock evaluation it is now possible to completely describe all core and chips collected at sub millimeter resolution.

Using machine learning and Artificial Intelligence technology it is possible to automate many parts of the process to produce unique datasets cheaply and quickly. A selection of imaging technology types are discussed below along with some products of use in the oilsands and other plays.

NEW IMAGING TECHNOLOGIES High Resolution Photographs With the advent of cheaper high performance digital cameras and lenses (Text-figure 1) it is now possible to take photographs of core and chips with resolutions on the order of 25 microns (the sand/silt boundary is 64 microns). It is possible to increase the resolution to the micron level by using focal plane stacking of images and subsequent processing to create an in-focus image. To achieve this quickly and accurately it has been found that robotic control of the camera mount and its controls is the optimum methodology.

A biproduct of the automation is that the exact location of the image is known and can be used subsequently to produce strip images and sampling locations.

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SWIR Short Wave Infra Red (SWIR) scanners have been available for a number of years but it is only recently that the technology has been come robust and to not need external cooling (Text-figure 2). Scanners can now be obtained which collect data from the 9002500 nannometer wavelength range with a scan width of the order of 0.5 millimeters.

The SWIR energy is absorbed by molecules within the rock at different wavelengths and these unique spectra are used to determine the mineralogy. Each received pixel can be subdivided into less than 10 nannometer wavelengths subsets for this investigation.

The technology is good for resolving weakly bonded molecules such as carbonates and hydrocarbons but cannot resolve those with strong bonds such as iron sulphates.

However, the latter can be resolved using XRF scanning.

XRF X Ray Fluorescence (XRF) uses X rays to bombard a core or chip sample and record the fluorescence generated at different wavelengths after the excitement is removed. This fluorescence is related to the type of molecules present. In the past the technology was only able to resolve a certain number of elements but, with the advent of helium emersion and higher energies, the spectrum has been widened to include sodium (useful in clay discrimination) and metals. The instrument is a spot sampler and needs time to collect the fluorescence energies though this again has been speeded up and is now often used with robotic positioning.

The technology is complementary to SWIR and used in conjunction as a quick and powerful way to generated mineralogical data, along with bitumen saturation.

Figure 1: Core being imaged using a camera system mounted on a robotic frame

Figure 2: A state of the art short wave infra red scanner mounted on the robotic frame (Continued on page 20...)

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TECHNICAL ARTICLE (Continued from page 19...)

INTEGRATION CHALLENGES The very large amount of data created with each picture and scan has required the use of cloud computing to integrate and store the huge datasets. Also machine learning and artificial intelligent algorithms have to be used to speed processing and allow real time interrogation of the products required. An example is the use of image recognition technology to look at core scans which can be used to outline all the mud laminae or breccia within a core (Textfigures 3-4). The data can then be used to determine the density of mud present in a unit and determine the likely hood of the mud altering the permeability of the rock to steam or solvent.

APPLICATIONS OF ROCK SCANNING Reserves It is now possible to obtain the oil content of a sandstone at half a millimeter intervals along the complete length of a core. The total volume of hydrocarbon can then be calculated with increased accuracy.

Also, the recovery factor, using the chosen extraction technology, can be determined at significantly higher resolution. The presence of gas, lean and water-rich zones can be located and various cutoffs applied to determine the chances of their presence altering the oil recovery. The data can be plotted as a curve and integrated with FMI logs and lower resolution standard suite curves to further resolve the reservoir properties.

Chip Substitution For Coring The collection of chip samples which are on depth, containing minimal cavings and with known chemical contamination is a major challenge for drillers. Often expensive core is cut rather than spending time examining the chips. However, new collection technologies tied in with detailed drilling records, such as Pason, create chip samples which are suitable for analysis. The caved chips can be automatically removed after scanning, using image analysis, to leave a clean sample for description and investigation. Clay mineralogy, cement typing and even geomechanical properties can be resolved so that the placement of frac charges can be optimised as well as the location of flow control devices. This chip dataset can now be used to the fullest and even stored chips can be scanned for

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Figure 3: a RedGreenBlue image of a mud breccia within an oilsands pay zone. The breccia particles are outlined in red with the maximum apparent length and breadth labelled in blue. The yellow circles are large sand grains showing they are present within the breccia unit. Computer analysis of the core separated the mud from the oilsands so that volumetric analysis can be automatically calculated.

Figure 4: Computer interpretation of the apparent dip of mud laminae found in an oilsands core. information.

Geomodels The data available for geomodelling a play has always been fiscally constrained and time consuming to obtain. Also laboratory work is destructive and thus non reproducible, and rarely of statistical significance. In the past upscaling has been the solution to the data limits with the resulting reduction in accuracy of the model. The new datasets combined with the increasing computational power available, and artificial intelligence

protocals potentially make upscaling a thing of the past.

Baffles And Barriers The presence of mud laminae and breccia has often been recorded as ‘non-pay units’, with arbitrary cut offs and rarely described in detail. Using machine learning it is now possible to locate each laminae or breccia clast automatically and determine if it contains sandy laminae and bitumen filled trace fossils. Any sandy units are potential pathways for steam and solvent which reduces the effectiveness of the structures

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to act as barriers. Integration of this data with other techniques, such as bitumen geochemisty typing (microbial degradation profiling) has the potential to resolve the effectiveness of the baffling over time. It will also negate the use of thickness cut offs presently used in modeling which has lead to inaccurate models of fluid flow.

the maximum operating pressure over a wide area of the field. Scanned core is depth corrected to the centimeter level making mini frac placemen more accurate and into a known mineralogy. Correlation of the rock tested can then be made giving a higher confidence in the calculated Maximum Operating Pressure.

the modeling and selection of slotted liner sizes along with the controlling of the initial start up of the SAGD process. Furthermore, the technique merged with others has the potential to provide permeability data for the rock. Hitherto this has been generated using lab tests which take months to complete at significant costs.

Cap Rock Description And Modeling The current description of cap rock strength is based on the logging of core samples, petrophysically generated characteristics and integrating the data with mini frac tests. The latter are costly, nonrepeatable and performed in the well at a chosen depth determined using logs. Often no mineralogy is run on the core from the test interval. The data is then upscaled for the whole depth of the cap rock to determine

Grain Size And Shape Measurements The high resolution camera data can be merged with the SWIR scans to resolve the size and shape of hundreds of grains with one scan. This technology makes the resolution of grain size and shape possible over the entire pay zone, without using sieves or lasers. The technique is also non-destructive and repeatable producing curves of grain size change at P10, 50 and 90 intervals. This is especially important for

IN SUMMARY The new integration of high resolution scanning and imaging of core and chips is a step change in the description of rock properties not just in the pay zone but also the cap rock. The technology has great potential in unlocking new data sources, increase data accuracy and finally provide geological datasets which can be used to make production models which actually work.

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RESERVOIR ISSUE 5 • SEPTEMBER/OCTOBER 2018

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TECHNICAL ARTICLE

UNCERTAINTY IN GEOMECHANICS AND INDUCED SEISMICITY Scott McKean ABSTRACT The article discusses uncertainty with a focus on geomechanics and induced seismicity. It goes over some of the pitfalls in dealing with sparse data and presents some strategies for handling uncertainty better. A hypothetical analysis of induced seismicity in the Duvernay is used to show how best guesses, sampling approaches, and Bayesian statistics can affect important decisions.

INTRODUCTION Our work as geologists and engineers involves extremely complex environments.

The subsurface involves a lot of uncertainty, regardless of whether we are exploring, drilling, or operating. This article revisits the statistics we tried to avoid in undergrad and showcase why it is useful in the subsurface where we typically have a (very) limited amount of data. It walks through statistical frameworks for dealing with uncertainty, specifically focusing on geomechanics and induced seismicity.

a framework developed by Dr. Maurice Dusseault when assessing hydraulic fracturing related problems (see Shafiei et al. (2018) for a working example).

Dusseault’s Hierarchy of Needs, shown in Figure 1, allows teams to prioritize the information used for geomechanical decisions and filter out unnecessary noise.

The framework progresses from a high-level structural interpretation and progressively moves into finer levels of detail. It provides both a playbook for data collection and a guide to analysis. Similar frameworks are used in play evaluation, operations, and financial analysis and, in my opinion, are crucial for any successful decision. It’s also no surprise that geology tops the hierarchy in most of them.

It’s important to divide uncertainty into the natural variability that exists in the earth and uncertainty that results from our imperfect understanding of that variability.

If we had a crystal ball that revealed the subsurface perfectly, natural variability would still exist and would need to be considered. Unfortunately, geophysicists haven’t released a crystal ball inversion yet and our imperfect understanding almost always overshadows the ground’s natural variability. Variability and uncertainty are usually lumped together and can be difficult to deal with.

The first strategy that is often used to handle uncertainty, but seldom discussed, doesn’t involve any math. It involves using a conceptual framework for the evaluation and prioritization of information. In my mind, this is far more important than statistical analysis and without it, any statistical analysis would be deeply flawed. In geomechanics, I often refer to

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Figure 1. Dusseault’s Hierarchy of Needs for hydraulic fracturing. Conceptual information is prioritized from top to bottom in terms of how it should be collected. It also prioritizes the importance of specific geomechanical parameters when conducting an analysis.

THE TARNISHED MEAN

presenting a probability curve when asked a yes/no question (for good reason). As professionals, this prompts us to present a “best guess” based on the information we have at hand. This intuitively and mathematically makes sense since our best guess should represent the P50 or maximum likelihood estimate. But we need to be careful with how we determine our best guess, especially for uncertain data and skewed distributions.

There are two pitfalls with single point estimates which I’ll illustrate using matrix permeability data from the Kakwa Montney and Kaybob Duvernay (Figure 2). First, we don’t effectively communicate how “certain” we are about a parameter.

The standard deviation (or variance) should always accompany a value because variance is the quantification of uncertainty. In Figure 2, we are more “certain” about the permeability data from the Duvernay than the Montney because of the spread in the probability distributions.

Most professionals grasp this, but it’s so important to this article and how we make decisions that it’s worth reiterating. Second, we need to be very careful about what central tendency measurement (i.e. best guess) we use. We learn about the mode, median, and mean in university, but quickly forget them because all of our classes focus on normal distributions. The world isn’t normally distributed, and these measures have big consequences when dealing with rock properties. In Figure 2, the central tendency measures are consistent for the Duvernay because it is a relatively well defined and symmetric distribution (albeit it with a huge lower tail). But, our best guesses vary by three orders of magnitude for the Montney because it is a less certain distribution. This simple example shows the importance of considering data visualization, variance, and an appropriate central tendency measurement before entering the AVERAGE() function in Excel.

Decision makers prefer clear, singular answers and are generally wary anyone

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TECHNICAL ARTICLE

θ, µ) equation for evaluating fault failure (Equation 4).

Figure 2. Pulse-permeability data plotted on a logarithmic scale for the Kaybob Duvernay (blue) and Kakwa Montney (red) Formations.The mean (solid), median (dashed), and mode (dotted) lines for each distribution are shown.

INDUCED SEISMICITY & THE MOHR COULOMB EQUATION My research group and I study induced seismicity - earthquakes attributable to industrial activities that are large enough to be felt at surface (generally local magnitude (ML) 2 or above on the Richter scale).

Induced seismicity is a major challenge for the Canadian energy sector, especially in the Duvernay. Many researchers like Hitzman et al. (2012) have shown that oil and gas activities have a significant potential for triggering seismicity by either increasing the pore pressure around a fault or perturbing the in situ stress regime.

Some of the largest earthquakes attributed to hydraulic fracturing have been observed in the Devonian strata of the Horn River Basin (ML 4.36, Farahbod et al., 2015) and the Duvernay (ML 4.44, Schultz et al., 2015 and Atkinson et al., 2016).

The rest of this article focuses on the influence of uncertainty on a hypothetical induced seismicity analysis.

Most practitioners use Mohr-Coulomb (MC) failure theory (Mohr, 1900; Labuz and Zang, 2012) to analyze fault activation. It’s relatively simple and assumes that a fault will trigger once the shear stress (τ) on the fault plane exceeds the shear strength of the fault (τ_f ). This in turn is a product of the fault cohesion (c), the normal stress on the fault plane (σ_n), the pore pressure in the fault (u), and the coefficient of sliding friction (μ) (Equations 1 to 3 - Jaeger, 1959). We can resolve the shear and normal stresses on a fault based on the angle between the minimum horizontal stress and the fault azimuth using Equations 1 and 2 (a zero angle results in pure normal stress). The above equation can then be combined with fault strength (Equation 3) to create a six-parameter (c, σ_h, σ_H, u,

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A positive hydraulic perturbation decreases the effective normal stress (σ_n-u) and the fault’s frictional shear resistance.

This is suspected to cause the majority of earthquakes since friction provides the majority of a fault’s strength. In most cases, cohesion is neglected or considered to be less than 3 MPa (Zoback, 2010). It’s also possible to “remotely” trigger a fault by increasing the total shear stress acting on it, which is generally caused by volumetric changes from injected fluid and proppant in hydraulic fracturing. This might not be a major contributor in “soft” clay-rich reservoirs like the Duvernay, but volumetric strain can ramp up quickly in “stiff” low porosity reservoirs like the Montney.

INDUCED SEISMICITY DUVERNAY

IN

THE

Tectonics and structural accommodation leave most areas of the crust critically stressed. Induced seismicity risk can develop in any tectonic environment, but overpressured1 regions are particularly susceptible. If the right conditions exist, it becomes possible for a minor perturbation to trigger seismicity. Unfortunately, the Kaybob area of the Duvernay may be an unfortunate example of a formation with the right conditions for IS. It is overpressured and subject to a relatively high difference between the maximum (σ_H) and minimum (σ_h) stresses, resulting in high shear stress. A large number of the faults in

the Kaybob strike north and are therefore well oriented for shear slip from a northeast striking σ_H (Nelson, 2001; Maxwell, 2009).

There are two possible explanations for the high propensity of north striking faults.

Stress relaxation and a rotation of the σ_H azimuth during recent orogenies like the Jurassic Cordilleran deformation may have occurred (Wright et al., 1994)2. The fault formation may also have been caused by the presence of the Chinchaga rift basin, which is an extensional structure that generates high angle normal faults by combining reef building processes and Precambrian basement faulting (O’Connell et al., 1990)3.

Assuming that this provides a sufficient framework for the presence of north-striking faults and causal explanation of IS in the Duvernay4, we can continue investigating the probability of induced seismicity by moving through Dusseault’s Hiearchy of Needs. This analysis focuses on the current reservoir stresses (#2 in the hierarchy and σ_h, σ_H, and u in the MC equation) and the orientation and strength of the fault (#6 in the hierarchy and c, θ, and µ in the MC equation) for brevity. But, determining how hydraulic fracturing perturbs the stress regime around a fault (#3 through #5 in the hierarchy) is hugely important and worthy of several more articles (and a lot more research). Let’s look at several scenarios for how we would interpret the MC equation and its parameters with uncertainty in mind.

Scenario 1: Central Tendency Values Lela et al. (2017) used the MC equation to screen faults and setup a geomechanical model. Their best guess of reservoir stresses and fault strength was used to evaluate the effects of a completion, with the input values in Table 1. The model showed

Soltanzadeh et al. (2015) & Fox et al. (2015)

Parameter

Lele et al.

(2017)

Mean

Distribution

Shape

Scale

θ (°)

45

45.7

Normal

45.7

8.9

c (MPa)

0

1.5

Gamma

3.75

2.5

σ_H (kPa/m)

27.2

29.5

Normal

29.5

1.3

σ_h (kPa/m)

19.0

21.0

Normal

21.0

1.0

u (kPa/m)

15.8

16.5

Gamma

495

30

µ (-)

0.6

0.6

Gamma

98.6

164.4

Table 1.The mean values from the Duvernay studies of Lele et al. (2017), Soltanzadeh et al. (2015), and Fox et al. (2015).The light red values the input values (or hyper parameters) of the parameter distributions.

The 95% confidence intervals for each distribution match the ranges provided in Soltanzadeh and Fox et al.’s study.

(Continued on page 24...)

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TECHNICAL ARTICLE (Continued from page 23...) that the fault was stable with a 0.9 MPa “capacity” prior to a treatment and that relatively minor pressure perturbations could cause failure. If we were to repeat this analysis with the mean values from Soltanzadeh et al. (2015) and Fox et al.

(2015) and an assumed cohesion and friction, the fault now has a “capacity” of 5 MPa. This would be enough to keep the fault in Lele’s analysis stable despite a seemingly small change in parameters.

Both studies show that an “average” fault with an “average” orientation should be stable given a moderate separation between hydraulic stimulations and the fault. This is good news, but is it realistic? How certain are we of that answer?

other hand, draws random samples from a probability distribution. The range for the parameters is nearly identical in both approaches, but the focus of the sampling differs significantly. Figure 4 compares the uniform and normal distributions – it shows that the bulk of the area under the probability density5 curve lies in the center of the normal distribution, as opposed to being equally distributed under the uniform distribution.

Scenario 2: The Sensitivity Tornado & Sampling Techniques The next approach to uncertainty is to evaluate model sensitivity. We systematically analyze possible outcomes based on best/worst/average scenarios or a sampling of a range of parameters that are often represented in a Tornado diagram (Figure 3). But, we need to be careful because the results of this approach depend on how we sample the parameters, which I’ll show by comparing grid sampling to a bootstrap Monte Carlo analysis.

10.1%. This difference will increase with every parameter we add to our models, to a point where uniform grid sampling gives nonsensical answers for high dimensional analyses (a twenty parameter material balance model for example).

In this example, both “best guess” approaches reported a stable fault, but our sampling approaches showed that we could expect a critically stressed fault 10% of the time. This could significantly affect our development strategy if the shut-in costs from a red light seismic event (Schultz et al., 2017) are considered. But we still have a huge problem if our model predicts a failure rate that is much higher (or lower) than what we’ve actually observed. How do we update this model to reflect our real observations?

Figure 4. A comparison of a uniform distribution for pore pressure with a normal distribution. The area under both curves sums to unity and the horizontal and vertical axes are the same for both plots.

Figure 3. A tornado diagram of the parameters used in the grid sampling and bootstrap Monte Carlo analysis. The width of the bars was determined using z-score standardization. The centered bold value represents the mean of the distribution. The left and right values represent the 95% confidence interval.

Grid sampling randomly resamples each parameter, assuming a uniform distribution across the entire parameter range. The bootstrap Monte Carlo procedure on the

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The results of grid and bootstrap sampling are compared in Figure 5, by plotting the shear stress against the effective normal stress. This plot is exactly the same as a Mohr circle plot, with a single point for each fault and stress combination. The two plots may look similar, but take note of the highest density region in each plot.

The grid sampling approach (somewhat unsurprisingly) has a uniform distribution of densities whereas the bootstrap resampling focuses on the central portions of the distribution. This significantly affects the calculated probability of failure - grid sampling calculates a 13.6% probability of triggering a fault whereas the bootstrap Monte Carlo calculates

Figure 5. An illustration of grid sampling (left) and bootstrap Monte Carlo (right).The plots show the stress states for 10,000 samples, showing the resolved effective shear stress against normal stress on a fault. The points are semi-transparent and higher density areas are darker.The grey lines show each realization of the MC failure envelope, with the mean value plotted in black. Points denoting a triggered fault are plotted in red.

Scenario 3: Bayesian Analysis & MarkovChain Monte Carlo Analysis

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TECHNICAL ARTICLE

A maladjusted model is a common problem in engineering analysis. A conventional approach would history match the model by adjusting the parameters near the top of the tornado diagram. We would torture the data until it confesses the “right” answer.

Yet, this approach moves us in the opposite direction of what probabilistic thinking is trying to achieve. We want to develop a model that accurately predicts an outcome given messy and noisy data. Changing our input parameters ad hoc divorces our model from reality and effectively throws away all the data that we spent considerable time and money obtaining.

Fortunately, Thomas Bayes and his contemporaries developed a statistical method for updating our models with observed data. Bayesian statistics allows us to build a model using our best understanding of its parameters and then update it to reflect our actual observations.

This helps us make better decisions under large uncertainties. Bayes rule (Equation 5) calculates the updated (i.e. the posterior or P (X|D)) probability for a model’s parameters, conditional on the observed data. This is based on a normalized distribution of how our data is generated (i.e. the likelihood or P(D|X)) and our understanding of the model parameters (i.e. the prior or P(X)). Bayesian statistics is growing rapidly – it is the base for many machine-learning algorithms and there are lots of open source tools for doing it. See Jordaan (2005), Gelman et al. (2013), and Kruschke (2014) for some great references.

It can be challenging to setup and analyze a Bayesian model, but the results can be impressive. For induced seismicity, we can separate the MC equation into what we are trying to predict (whether we trigger a large event or not) and what we are using as predictors (the parameters of the MC equation). The predictors can be separated into observable and latent/ unobservable parameters. It’s possible (albeit difficult) to measure the stresses before a completion program (σ_h, σ_H, and u) and the azimuth (θ) of a fault that did (or didn’t) slip. But, we will never be able to measure the cohesion and sliding friction (c and µ) of the fault. We can link the MC equation to a trigger or not (i.e. binary) IS outcome using a logistic or log odds function (Equation 6). This creates a hierarchical logistic regression model

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from which we can infer c and µ and the posterior probability of failure6 given our observed completions.

The stress and azimuth from the bootstrap Monte Carlo analysis were used to simulate hypothetical observations with an

observed failure rate of 4% (Figure 6). The distributions for c and µ from Table 1 were used as priors in the model. A Bayesian logistic regression was done for each observation and the posterior distributions for cohesion, the coefficient of sliding friction, and the probability of failure were calculated using a Markov Chain Monte Carlo (MCMC) approach. The MCMC method travels around the P(D|X)P(X) space and samples the posterior, which is effectively a tricky and hard to compute high dimensional integral. It does this with an evolutionary algorithm that maximizes the number of samples taken from high probability regions and provides robust results.

As we provide the Bayesian analysis more observations, it focuses the posterior on the data and moves away from our prior assumptions. Figure 7 shows how the probability of failure is updated as we move from 10 to 1000 observations. Even with 10 observations, the posterior already shows that something isn’t right and that the assumed “certainty” we had in the prior is misplaced. More observations increase our confidence in this conclusion,

Figure 6. An illustration of 1000 simulated completions, 44 of which triggered significant seismicity. The grey lines show each realization of the MC failure envelope, with the mean value plotted in black.Triggered events are shown in red.

eventually centering on 4.5% - the observed probability of failure.

The regression also calculates the posterior distribution for cohesion and friction (Figure 8). These distributions now reflect both our prior information (which could come from academic studies for example) and our observations. The coefficient of friction is much more sensitive to our observations than cohesion – a conclusion replicated in several other analyses that was only revealed through Bayesian inference.

Figure 7. The results of the Bayesian logistic regression, showing the prior and posterior probability of failure. The posterior quickly shifts away from the prior, but has low confidence with 10 observations (left). The credibility of the posterior increases with 100 (middle) and 1000 (right) observations.

Figure 8. Prior and posterior distributions for the MC equation in the Bayesian logistic regression with 100 observations. The coefficient of friction (left) changes much more than the cohesion (right). The observations support a more certain friction distribution and actually decrease the certainty of the cohesion distribution.

(Continued on page 26...)

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TECHNICAL ARTICLE (Continued from page 25...)

CONCLUSION The goal of this article was to discuss and promote careful use of uncertainty in geology and engineering. I personally don’t find probabilistic thinking that intuitive and find Bayesian statistics especially confusing.

But, I’ve been inspired by what can be accomplished using a statistical framework and hope that you’ll consider some of the concepts I’ve introduced. Our industry is full of big decisions based on sparse data, and probabilistic methods and thinking are needed to handle them effectively.

To summarize the article takeaways, use a conceptual framework to guide analysis and decision making well before plotting and analyzing data. This article introduced Dusseault’s Hierarchy of Needs as a geomechanical example. Be aware of how single-point estimates can lead you astray and why sampling techniques need to be used with care. Consider Bayesian techniques as a method for incorporating observations into your model. This article used hierarchical logistical regression to robustly incorporate IS observations with the MC equation and infer fault strength parameters.

ACKNOWLEDGMENTS The Canada First Research Excellence Fund and Microseismic Industry Consortium sponsor my Ph.D. research. This article wouldn’t have been possible without the guidance of my supervisor Dr. Jeff Priest, my co-supervisor Dr. Jan Dettmer, and my research team lead Dr. David Eaton. This work grew out of the ReDevelop program coordinated by Dr. Celia Kennedy and was shaped in collaboration with Jieyu Zhang and Suzie Jia. I’m so grateful to be part of an amazing geomechanics community with some amazing mentors that include Patrick Collins, Amy Fox, Shawn Maxwell, Patrick McLellan, Steve Rogers, and Mehrdad Soltanzadeh. The analysis in this article wouldn’t have been possible without JAGS (Plummer et al. 2017) and R (R Core Team 2017).

REFERENCES Atkinson, G.M., Eaton, D.W., Ghofrani, H., Walker, D., Cheadle, B., Schultz, R., Shcherbakov, R., Tiampo, K., Gu, J., Harrington, R.M., Liu, Y., Van Der Baan, M., Kao, H., 2016. Hydraulic fracturing and seismicity in the Western Canada Sedimentary Basin. Seismol. Res. Lett. 87, 631–647. doi:10.1785/0220150263

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Farahbod, A.M., Kao, H., Walker, D.M., Cassidy, J.F., Calvert, A., 2015. Investigation of regional seismicity before and after hydraulic fracturing in the Horn River Basin, northeast British Columbia. Can. J. Earth Sci. 52, 112–122. doi:10.1139/cjes-2014-0162 Fox, A.D., Soltanzadeh, M., 2015. A Regional Geomechanical Study of the Duvernay Formation in Alberta, Canada.

Geoconvention 2015, Calgary, Alberta.

Gelman, A., Stern, H.S., Carlin, J.B., Dunson, D.B., Vehtari, A., Rubin, D.B., 2013. Bayesian Data Analysis.

Hitzman, M.W., 2012. Induced Seismicity Potential in Energy Technologies, National Academies Press. doi:10.17226/13355 Jaeger, J.C., 1959. The frictional properties of joints in rock. Geofis. Pura e Appl. 43, 148– 158. doi:10.1007/BF01993552

Plummer, M., 2017. JAGS version 4.3.0 user manual.

R Core Team, 2014. R: A language and environment for statistical computing.

R Foundation for Statistical Computing, Vienna, Austria. 2013.

Schultz, R., Stern, V., Novakovic, M., Atkinson, G., Gu, Y.J., 2015. Hydraulic fracturing and the Crooked Lake Sequences: Insights gleaned from regional seismic networks. Geophys. Res. Lett. 42, 2750–2758. doi:10.1002/2015GL063455.

Schultz, R., Wang, R., Gu, Y.J., Haug, K., Atkinson, G., 2017. A seismological overview of the induced earthquakes in the Duvernay play near Fox Creek, Alberta. J. Geophys.

Res. Solid Earth 122, 492–505.

Jordaan, I., 2005. Decisions under uncertainty: probabilistic analysis for engineering decisions. Cambridge University Press.

Wright, G.N., McMechan, M.E., Potter, D.E.G., Mossop, G.D., Shetsen, I., 1994.

Structure and architecture of the Western Canada sedimentary basin. Geological Atlas of the Western Canadian Sedimentary Basin 4, 25–40.

Kruschke, J., 2014. Doing Bayesian data analysis: A tutorial with R, JAGS, and Stan.

Academic Press.

Zoback, M.D., 2010.

Reservoir Geomechanics. Cambridge University Press, Cambridge, U.K.

Labuz, J.F., Zang, A., 2012. Mohr Coulomb failure criterion. Rock Mech. Rock Eng. 45, 975–979. doi:10.1007/s00603-012-0281-7

Endnotes

Lele, S.P., Tyrrell, T., Dasari, G.R., Symington, W.A., 2017. Geomechanical Analysis of Hydraulic Fracturing Induced Seismicity at Duvernay Field in Western Canadian Sedimentary Basin. Geoconvention 2015, Calgary, Alberta.

Maxwell, S.C., Jones, M., Parker, R., Miong, S., Leaney, S., Dorval, D., D’Amico, D., Logel, J., Anderson, E., Hammermaster, K., 2009.

Fault activation during hydraulic fracturing.

SEG Tech. Progr. Expand. Abstr. 2009 1552– 1556. doi:10.1190/1.3255145

A region with the pore pressures well above the hydrostatic gradient of 10 MPa/km 1

2

aults generally form at 30 degrees to the F maximum horizontal stress, so barring other structural influences from reef formation or rift basins, a stress rotation must have occurred.

3

This is also an active area of U of C research.

4

orgive the overly simple overview of the F geology – I’m an engineer after all.

5

robability density is a measure of the P likelihood (or odds) of sampling a range of values. In Figure 4, for example, the probability of pore pressure being between 16 MPa and 17 MPa is 35% for the uniform distribution and 50% for the normal distribution.

6

is approach is involved and the details Th are omitted here for brevity. It is the subject of a technical paper in preparation.

Nelson, R., 2001. Geologic analysis of naturally fractured reservoirs. Gulf Professional Publishing.

O’Connell, S.C., Dixon, G.R., Barclay, J.E., 1990.

The origin, history, and regional structural development of the Peace River Arch, Western Canada. Bull. Can. Pet. Geol. 38A, 4–24.

RESERVOIR ISSUE 5 • SEPTEMBER/OCTOBER 2018

TECHNICAL ARTICLE

TECHNICAL EVALUATION OF THE CARBON/OXYGEN LOGS RUN IN BLOCKS V AND VI OF THE LAMAR FIELD IN THE MARACAIBO LAKE BASIN, VENEZUELA Rafael Becerra D. - Department of Physics, University of Alberta. Hugo Govea – PDVSA Petroleos de Venezuela.

ABSTRACT

There are mainly two modes in which these tools determine the fluid saturation: (1) thermal neutron cross section or Sigma (capture mode), and (2) C/O ratio (inelastic scattering mode). The first one can only be used when the salinity of the formation water is higher than 25000 ppm, since the Sigma of oil is similar to fresh water. Goode et al (1994). When the formation water salinity is lower than 35000 ppm, the C/O ratio is used to determine the presence of hydrocarbons in the reservoir based on the principle of high C/O ratio = Oil.

Carbon/Oxygen (C/O) logging technology can be used to evalu¬ate candidate wells to be recompleted since they meas-ure the actual oil saturation on cased holes and allows one to identify by-passed zones independently of water salinity.

However, in the last 15 years, the use of this tech¬nology for monitoring residual hydrocar-bon saturations in the Maracaibo Lake Basin, West Venezuela, has decreased to the point that it has not being exploited recently, mostly due to lack of confidence in the results given for these tools in the past.

My investigation sought the reasons why such results have not been as expected, analyzing the causes of discrepancies between the results and the actual production behaviour, to determine whether it is associated with reservoir characteristics, hole environment conditions or due to the interpretation of the acquired data.

In this study it was found that poor prejob planning was largely responsible for previous disappointing results, since half of the wells where the technology was applied did not meet the conditions required.

Another significant finding of this study was that C/O data can actually be processed and interpreted by operators, using a commercially available petrophysical software. This allows one to obtain in most cases, quantitative results similar to those given by service companies, which also provides a way to control the quality of the interpretations before making any decision that involves high financial investment.

INTRODUCTION To determine the hydrocarbon saturation from well logs in cased wells, conventional open hole tools do not work due to the presence of casing, tubing, cement and

Fig. 1. Geographical map showing the location of study area. Modified from Castillo and Mann (2006). completion fluids. In order to know the residual hydrocarbon saturation in this type of wells, there are few options available.

One of the most useful tools are the socalled pulsed-neutron tools, which emit high neutrons to the formation through the wellbore fluids, the casing/tubing and cement.

Fig. 3. Windows method to determine the relative concentration of chemical elements in the formation. Once the Carbon and Oxygen concentrations are quantified, a C/O ratio is determined. High C/O ratio= Oil. Low C/O ratio = Water. Eyvazzadeh et al (2004).

METHODS 8 well were selected out of 38 with C/O logs, run between 2000 and 2007 in the Maracaibo Lake Basin.

Fig. 2. Inelastic scattering of neutron producing distinctive gamma rays depending on formation mineralogic composition and fluids in the poral space. D. Avendano (2006).

To achieve the objective of this investigation, the data available from three different service companies was reinterpreted “inhouse”, by using a commercial petrophysical software and a linear equation for oil saturation (which had not been done before in the operating company, where I worked as an intern during this study), taking into consideration two main factors: (Continued on page 28...)

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TECHNICAL ARTICLE (Continued from page 27...)

(1) the configuration of the completion of the well, such as the presence of double tubular (e.g. casing and production tubing), the quality of the cement behind casing, the presence of open perforations, and hole/ casing diameter.

(2) The wellbore fluid distribution, or holdup (volumetric fraction occupied by each fluid phase at a certain depth).

Table 1. Summary of conditions of the two wells presented in results.

Fig. 4. Different factors considered during the evaluation of the results of C/O data.

In addition, the results were compared with the production data and the petrophysical interpretations from neigh-bouring wells drilled before and after the C/O log.

Finally, the data was re-interpreted inhouse using a mathematical linear equation in order to compare the results with those of the vendors along with production data and neighbouring wells.

RESULTS Two wells (well A and B) are presented to show how the completion configuration and the knowledge of the fluid’s holdup is critical for obtaining a satisfactory interpretation of the results of C/O logs. In terms of porosity, both well had values of more than 15% along the log interval which is favorable for the use of the technology.

Regarding the casing diameter, both well fulfilled the requirement of the technology with 5.5in (139.7mm) casings. However, Well A was logged under challenging completion configuration and without the knowledge of the fluid’s hold-up, which is believed leaded to the misinterpretation of the results, since C/O log interpretation was not in accordance with the production data.

In the other hand, the results of well B were in accordance with other sources of information such as production data and open hole logs.

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Fig. 6. Composite log showing the fluid contacts in the wellbore and how in most part of the log interval the fluid hold-up was unknown.

Well A Fig. 5. Completion diagram of well A showing the log interval.

No match between C/O and production This well was logged through a complex completion scenario, with producing tubing and three unknown fluids in the wellbore (figures 5 and 6). Oil satura¬tions (So) computed from C/O log ranged from 10 to 40 %. In spite of the low So values, the operator de¬cided to perforate the well in the interval 12266ft – 12320 ft (3738.7m - 3755.1m), appar-ently based on neighbouring‘s wells data.

After the perfora¬tion, the well produced 99% oil (1000 BBL/day) during 3 years (fig.

7), which contradicted the interpreta¬tion from the C/O logs. One possible reason for the discrepancy is the lack of knowledge of the fluids in the wellbore (fig. 8). The knowledge of fluid’s hold-up is critical during the processing of the data obtained from C/O logs and the failure of include this information may lead to the

Fig. 7. Production graph from well A showing the production of oil and water before and after the C/O log. misinterpretation of reservoir fluids.

Well B Good match between neighbouring wells

C/O

and

This well was evaluated without the presence of producing tubing in the wellbore which made less difficult the interpretation of the C/O data (fig. 8).

Oil saturations (So) computed from C/O logs in the upper interval ranged between 55%-65% which was in accordance with a neighbouring well drilled 3 months later the C/O log (Fig. 9).

RESERVOIR ISSUE 5 • SEPTEMBER/OCTOBER 2018

TECHNICAL ARTICLE

lower interval, the C/O log showed high oil drainage with So averaging 40% (Fig. 9). Despite this information, the operator perforated the interval getting a production of 70% of water.

The results obtained from C/O in this well demonstrated to be very useful to evaluate the accuracy of the technology since they were corroborated by a neighbouring well’s production data. Unfortunately, due to the lack of confidence on this technology in the Maracaibo Lake Basin, the operator made its decisions ignoring the C/O data and obtaining as a result high water cut production from the lower interval and did not exploited the reserved detected by the C/O in the upper interval.

Fig. 8. Completion diagram of well A showing the log interval

INNOVATIVE RESULTS: INTERPRETATION

IN-HOUSE

One of the more valuable findings of this project was the application of a mathematical equation to process an interpret the C/O curves in-house (by the operator). In fact, one of the possible reasons why the operator company where this project took place had lack of confidence in the results is that their petrophysicists are not able to interpret this type of logs by themselves.

This simple linear mathematical equation was applied by zones based on the C/O curve responses which is also a result of the tool response to the reservoir fluids and minerals and to the other environmental elements such as wellbore fluids, completions accessories and cement behind casing. When comparing the results, it was observed a very good match between the interpretation provided by the vendor and the one obtained in this project (figures 10 and 11).

CONCLUSIONS

Fig. 9. Comparison of the results of C/O log in well B with two neighbouring wells.

The upper zone was not perforated in this well. However, the neighbouring well produced oil with only 10% of water in the same unit. In the other hand, over the

RESERVOIR ISSUE 5 • SEPTEMBER/OCTOBER 2018

Fig. 10.Vendor vs In-House Interpretation showing a very good match.

The C/O technology can be applied to evaluate candidate wells (cased holes) to be recompleted by the identification of by-passed zones in formations where the water salinity is low or unknown, as long as a good pre-job planning is performed for the selection of the wells. Actually, it was found that the wells evaluated either did not completely fulfill the logging environment conditions required by the technology or the uncertainty was too high due to the lack

Fig. 11. Composite log showing in tacks 4 and 5 how the water saturation interpretation from vendor and this project match very well. Track 1: Volume of clay. Track 2: resistivity curves (OH).

Track 3: Calculated porosities from OH logs.Track 4: Vendor C/O water saturation. Track 5: In-house water saturation C/O interpretation. Track 6: C/O ratio far detector. of information on the wellbore conditions.

One of the main factor to be considered during the pre-job planning phase is the availability of other sources of data such as neighboring wells or production logs (PLT) in whose cases the C/O logs may not be necessary.

During the pre-job planning phase, an involvement of the petrophysicists of the operating company is key since they have a broader knowledge of the reservoir to be evaluated.

The uncertainty in the interpretation of C/O data was found to be high in the following conditions: (Continued on page 30...)

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TECHNICAL ARTICLE (Continued from page 29...)

1. Double tubular along the logging interval.

2. Hold-up unknown 3. Open perforations (wellbore fluid reinvasion) 4. Poor cement To reduce this uncertainty, it is highly recommended to run an independent sensor to know the holdup (Gradiomanometer, PLT) and, run a Cement Evaluation Log before the C/O log, information that will be useful during the interpretation of the results.

Finally, it was found that it is possible to interpret the C/O data in-house with a commercial petrophysical software, obtaining in most cases good quantitative results similar to the ones from the vendors.

This interpretation, along with the broader knowledge of the reservoir may be used as a

quality check of the interpretation provided by the vendors.

NOMENCLATURE C/O = Carbon/Oxygen ratio OH = Open Hole PLT = Production logs So = Oil saturation Sw = Water saturation Sw V = Water saturation from vendor Sw IH = Water saturation In-House

ABOUT THE AUTHOR Rafael is a PhD Student in the Depart¬ment of Physics at the University of Alberta, from where he also received his MSc. degree in Petroleum. He formerly worked as a Wireline Field Specialist for Schlumberger.

He is currently working on magnetic measurements on core samples to identify anisotropy and other petrophysical properties.

to Holocene structural and stratigraphic development in south Lake Maracaibo, Venezuela, inferred from well and threedimensional seismic data”. AAPG Bulletin (2006) 90 (4): 529-565.

Avendano D. “Reporte y Análisis del Registro PND-S Pulsed Neutron Decay – Spectrum. Precision. Ciudad Ojeda, (2006).

P.A. Goode, A.M. Sibbit and S.Y. Loid.

“Reservoir Saturation Determination in the Eromanga Basin Using Carbon/ Oxygen Logging”. SPE. Conference Paper, Melbourne, Australia 1994.

Ramsin Y. Eyvazzadeh, Oscar Kelder, A.A.Hajari, Shouxiang Ma and Abdallah M. Behair. “Modern Carbon/Oxygen Logging Methodologies: Comparing Hydrocarbon Saturation Determination Techniques”.

SPE. Conference Paper. Houston, Texas. 2004.

REFERENCES M. V. Castillo and P. Mann. “Cretaceous

GO TAKE A HIKE A unique sponsorship opportunity is available for individuals and companies!

VISIT WWW.CSPG.ORG/GTAH FOR MORE INFORMATION AND TO SEE THE AVAILABLE HIKES A group of dedicated hikers have documented hikes in Western Canada for CSPG. In addition to the stunning scenery you are a guided through, each hike has a short discussion of the geological background with annotated photographs of the area. These hikes originally appeared as part of the "Go Take A Hike" series in the CSPG Reservoir in honour of Cindy Riediger. The material was reworked and expanded with lots of additional supporting information added for those who want to know everything about where they are hiking. There are 83 hikes that will be compiled and are set to be published in early 2019

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RESERVOIR ISSUE 5 • SEPTEMBER/OCTOBER 2018

Congratulations to the GeoConvention 2018 Technical Program Award Winners

Title

Presenter

Award

Jimmy Zhang

Best Oral Presentation

The Ostracod Fm. in Alberta’s Deep Basin: Applying petroleum system fundamentals to identify an underexplored lacustrine basin

Geoff MacDonald

Best Oral Presentation

Fault Activation During Multi-Well Completion: Fault Slip to Ground Motion

Shawn Maxwell

Best Oral Presentation

Pushing the limits of the Montney at Gold Creek – From seismic to simulation Part 3

Pippa Murphy

Best Oral Presentation

Google your way to maximising geoscientific value.

Marc Boulet

Best Oral Presentation

Deciphering the subsurface and engineering controls on well performance in the Montney

Alexa Tomlinson

Best Oral Presentation (Honorable Mention)

Communicating the Value in GeoScience – Quantify, Communicate, Improve.

Jessica Galbraith

Best Oral Presentation (Honorable Mention)

Managing Induced Seismicity in Canbriam`s Altares Field - an update

Brad Bialowas

Best Oral Presentation (Honorable Mention)

Liz Lappin

Best Oral Presentation (Honorable Mention)

Learnings From FiberOptic Science Pad - ECA Swan Pilot

Petro-Lithium: The Evolution of Energy in Alberta

Mudstones and siltstones: geologically under-utilized sediments in Russell Stancliffe bitumen pay descriptions, with examples from the McMurray and Clearwater Formations

Best Oral Presentation (Honorable Mention)

What Lies Beyond the Rainbow

Steven Lynch

Best Poster Presentation

Geographic Information Systems For Seismic Line Optimization

Christopher Harrison

Best Poster Presentation (Honorable Mention)

A geomechanical comparison of the Duvernay and the Montney

Scott McKean

Best Student Oral Presentation

Influence of sedimentary facies on geomechanical properties in the Duvernay Formation, Fox Creek area, AB, Canada

Marco Venieri

Best Student Oral Presentation

New Insights about Organic Matter and Petroleum Migration from co-occurrence of two organic phases with contrasting properties in Lower Carboniferous Banff Formation

Yihua Liu

Best Student Oral Presentation (Honorable Mention)

Aaron Lang

Best Student Oral Presentation (Honorable Mention)

Noga Vaisblat

Best Student Oral Presentation (Honorable Mention)

Technical Evaluation of the Carbon/Oxygen logs Run in Blocks V and VI of the Lamar Field in the Maracaibo Lake Basin, Venezuela

Rafael Becerra

Best Student Poster Presentation

Seismic monitoring with continuous seismic sources

Tyler Spackman

Best Student Poster Presentation (Honorable Mention)

It’s About to Get a Lot Less Salty – Comparison of a Fluvial Outcrop to Estuarine Outcrops Using UAV-Based Outcrop Modelling in the Lower Cretaceous McMurray Formation

Derek Hayes

Best Student Poster Presentation (Honorable Mention)

Evaporite Sedimentology in South-Central Alberta: Prairie Evaporite and Lotsberg Formations

Elaine Lord

An Overview of Shale Gas Deposits in Eastern Canada

Ruiqiang Li

Graveyards of Industry – Exploring the effects of a resource-reliant economy on the towns of early Alberta Probabilistic approach to reservoir quality modeling of the Montney Formation in the Pouce Coupe Field

RESERVOIR ISSUE 5 • SEPTEMBER/OCTOBER 2018

Best Student Oral Presentation (Geology Focus) Best Student Poster Presentation (Geology Focus)

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TECHNICAL LUNCHEON

UPCOMING EVENTS Reservoir Geology of the Montney Formation from analysis of flowback and produced fluids, petrophysics and lithofacies analyses SPEAKER

ABSTRACT

Marc Bustin, Ph.D., P. Geol., FRSC | University of British Columbia, Department of Earth, Ocean and Atmospheric Sciences

R.M Bustin, A.M.M. Bustin, and J. Owen

Time: 11:30 am doors open Date: September 18, 2018 Location: Marriot Hotel, Kensington Ballroom 110 9 Ave SE, Calgary AB T2G 5A6 CSPG member ticket price: $44.50+gst Non-member ticket price: $55+gst Please note: The cut-off for ticket sales is 1:00pm, five business days before the event. September 11, 2018.

Detailed analysis of fluids and solids mineralogy and fabric from flowback waters from fifty Montney Formation horizontal well completions in Western Canada, when coupled with petrophysical and lithological analysis of core, provides insights into the reservoir geology, which in turn enables strategies for optimising well completions, production, and well surveillance.

The chemistry and volume of flowback fluids following well completions is a complex product of the mixing of connate water and completion fluid and fluid-rock interactions that includes

precipitation and dissolution of minerals, ion exchange, imbibition, and diffusion/ osmosis. In general, the chemistry and volume of flowback waters from Montney completions varies with the completion program, reservoir lithofacies, depth of burial, and hence geographically and stratigraphically. In detail; however, the flowback volume and chemistry varies with a plethora of variables most of which have multicollinearity. These variables include, completion fluid chemistry, number of stages, shut-in time, surface area of the fracture network/stimulated reservoir volume, length of flowback period, connate water chemistry, and ambient stress field.

The cumulative volume of flowback fluid

30th Annual CSPG/CSEG/CAPL 10km/5km Road Race and Fun Run Thursday, September 20, 2018

Register NOW! To register please go to www.cspg.org

Member Rate: $40+gst | Non-member rate: $50+gst | Student & In-Transition rate: $25+gst Join us on race day on an out-and-back course along the beautiful Bow River pathway. If you are looking for a competitive race or just want to have fun, come join us!

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RESERVOIR ISSUE 5 • SEPTEMBER/OCTOBER 2018

TECHNICAL LUNCHEON

from Montney completions ranges from about 15% to 30% of the volume injected.

The proportion of connate water in the flowback water, based on conserved element and isotope analyses, varies from about 10% to 60%, and the proportion of connate water increases with time of flowback. The total dissolved solids (TDS) of Montney flowback fluids range up to 230 000 mg/L, with Cl and Na ions accounting for about 75% to 95% of the total dissolved solids. Other major ions are Ca, K, Mg, Sr, and locally SO4. With cumulative flowback, the TDS and most ions, for all wells, increases linearly, although the rate of increase varies between wells, and with stratigraphy, lithofacies (parasequence), and geographic area. Deviation from the linear increase in TDS and conserved elements with cumulative flowback, reflects opening or closing of the fracture system(s) with declining pore pressure, variation in connate water chemistry and reservoir geology along laterals, and/ or fractures that have grown out of zone.

Geochemical modeling also indicates that the ions that deviate from the linear mixing model are impacted by fluid-rock interactions including precipitation, dissolution, and/or ion exchange

reactions. Reservoir surveillance using geochemical models coupled with analysis of the flowback and produced fluids provide a means of predicting and mitigating against salting and scaling in the reservoir, due to dehydration of saline connate water during gas production.

The mechanics of mixing between completion fluid and connate water is complex and poorly understood. Analysis of connate water and fluid saturations indicate that most of the unconventional Montney Formation is below irreducible water saturation. Yet the isotopic data indicates that a significant proportion of the flowback is connate water, even though the total volume of water recovered is generally much less than 30% of the total volume injected. Imbibition experiments and measures of wettability indicate the Montney has mixed wettability, but is preferentially oil wet. The spontaneous and forced imbibition/osmosis of drilling and completion fluids results in significant fracture skin damage, resulting in a decreased relative matrix permeability by up to two orders of magnitude. In addition, the imbibed completion fluid, depending on composition, may weaken

and ‘soften’ the fracture face promoting proppant embedment, early collapse of non-propped fractures, and creation of fines, which in turn may plug the proppant pack and stabilise emulsions.

The variably large proportion of completion fluid remaining in the reservoir after flowback is a product of the low initial reservoir water saturation, the increase in capillary pressure of imbibed completion fluids due to fluid-rock interactions, and much lower differential pressure during flowback than during completions.

BIOGRAPHY R. Marc Bustin is a Professor in the Department of Earth and Ocean Sciences at the University of British Columbia and president of RMB Earth Science Consultants. Bustin received his BSc and M.Sc. degrees from the University of Calgary and his PhD from the University of British Columbia.

Bustin is an elected Fellow of the Royal Society of Canada and a registered professional geologist in the province of British Columbia.

DigitCore Library and CoreSearch Databases Merged DigitCore Library acquired the www.CoreSearch.ca database on May 31st, 2018.

DigitCore Library now has depth-registered core images for ~9,000 wells in Western Canada and keeps expanding coverage every month.

24-7 online access to the DigitCore Library and CoreSearch.ca is by annual subscription for companies, organizations, and individuals.

DigitCore also offers its clients high-resolution photography of core for wells not already in the Library. Contact us to find out how you can get this work done for free.

The DigitCore Library is seamlessly integrated with DigitCore Software, the world’s first 3rdgeneration core logging and data integration application for geologists. You can analyze and interpret core directly from the high-resolution digital core images using our software.

To learn more, contact Rob Meurin at rmeurin@digitcore.com or Allan Powers at apowers@digitcore.com Phone 403-295-0588 for a DEMO

www.digitcore.com

RESERVOIR ISSUE 5 • SEPTEMBER/OCTOBER 2018

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TECHNICAL LUNCHEON

UPCOMING EVENTS When all else fails, try planar lamination - Possible insight into the Montney and other similarly fine-grained reservoirs SPEAKER Bill Arnott | Department of Earth and Environmental Sciences University of Ottawa

Time: 11:30 am doors open Date: October 16, 2018 Location: Marriot Hotel, Kensington Ballroom 110 9 Ave SE, Calgary AB T2G 5A6 CSPG member ticket price: $44.50+gst Non-member ticket price: $55+gst Please note: The cut-off for ticket sales is 1:00pm, five business days before the event. September 11, 2018.

ABSTRACT Planar-laminated strata are ubiquitous in modern and ancient sedimentary environments that range from the continental to deep marine, and include economically important units like the Montney Formation and other similarly fine-grained units in the Western Canada Sedimentary Basin and worldwide. Planar lamination indicates that bed-load sediment transport is more or less spatially uniform and irrespective of f low type (unidirectional, oscillatory, combined) a planar bed surface is the stable bed state, which commonly, and most intuitively, coincides with high-energy transport conditions. Under low energy conditions, on the other hand, and beginning at threshold transport, bed surface sediment transport typically becomes spatially non-uniform and the bed surface ornamented by an array of bed forms that build above and below the general bed level. Accordingly, the commonality of planar lamination, especially in shallow- and deepmarine settings, would suggest that a significant part of the sedimentary record was deposited under highenergy transport conditions. Puzzling

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then, is the equally, if not more common occurrence of planar-laminated strata that grade continuously upward to mud(stone) with no intervening unit suggestive of low-energy bed-load transport.

Based on experiments using sedimentpropelled density currents passing through a medical-quality CT scanner, it is argued that the absence of these low-energy structures is not related to incompatible flow speed, transport bypass or erosion, but instead to nearbed sediment concentration conditions that discourage spatially non-uniform sediment transport and the consequent initiation and amplification of bedsurface defects that otherwise would evolve into distinctively internally crossstratified bed forms. As expected these conditions are common in both coarseand fine-grained, high-energy density currents. Of particular note, then, is that these conditions also form in low (depth averaged) sediment concentration finegrained flows, which because of low sediment concentration also have low flow speed. It is these latter currents that are being increasingly recognized as the principal physical mechanism responsible for mobilizing and depositing much of the sediment in distal shallowmarine and deep-marine environments, including units like the Montney Formation and other non-conventional reservoir units around the world. It is in these settings where spatially uniform bed-surface transport should dominate, and accordingly, planar-laminated strata should, and does, dominate the sedimentary record. Notably also, these planar-laminated strata exhibit a distinctive alternation of centimetre- to sub-millimetre-thick, well-sorted clayrich and clay-poor laminae, which may have important implication on overall stratal rheology, and accordingly, fracture development and propagation.

BIOGRAPHY Bill Arnott is a Professor and current Chair of the Department of Earth and Environmental Sciences at the University of Ottawa. His research and that of his merry band of undergraduate, graduate and postdoctoral researchers is outcrop and laboratory based and focuses on sedimentary environments that range from the continental to the deep marine, sediment transport and depositional processes that range from unidirectional to oscillatory to combined, open channel to density currents, and increasingly the geochemistry of Neoproterozoic Earth.

RESERVOIR ISSUE 5 • SEPTEMBER/OCTOBER 2018

DIVISION TALKS

BASS TECHNICAL DIVISION TALK Clay mineralogy of the Duvernay and Muskwa Formation: Where have all the smectites gone?

SPEAKER Raphael Wust, PhD, PGeol., wust@ agatlabs.com | AGAT Laboratories,

Time: 12:00 pm Date: Thursday, September 27, 2018 Location: geoLOGIC Classroom (2nd Floor), Aquitaine Tower, 540-5th Avenue S.W. ABSTRACT The Muskwa and Duvernay Formations are contemporaneously deposited stratigraphic units of the late Devonian (Frasnian) in the Western Canadian Sedimentary Basin. The organic-rich and fine-grained sediments were deposited within adjacent basins north (Muskwa) and south (Duvernay) of the Peace River Arch on the western shelf of the North American Craton.

Despite their proximity, clay mineralogical compositions are markedly different and the mineralogical composition strongly influenced early unconventional oil/gas exploration activities.

In this presentation, several key aspects of clay minerals and clay mineral distributions across the formations will be discussed including: • Clay mineralogical compositions within the Duvernay and Muskwa formations • Smectite clay minerals in the Muskwa Formation • Diagenetic clay mineral transformations within the Muskwa Formation • Clay mineral variability Duvernay Formation

within

the

Variability in clay mineral compositions is observed in both formations, from the eastern shallow buried deposits to the western deeply buried deposits.

These changes infer a progressive clay

RESERVOIR ISSUE 5 • SEPTEMBER/OCTOBER 2018

mineral transformation with the basins due to increased burial pressure and temperature after deposition. However, it also allows us to make interpretations about possible original detrital clay mineral influx as well as paleoocean currents and paleotopographic relief of these sedimentary basins. The presentation will showcase some of these hypothetical and potential paleodepositional models.

In addition, a review of clay mineral crystallinity changes with increasing burial depth will be shown and implications for drilling activities highlighted.

BIOGRAPHY RAPHAEL WUST received his MSc in Geology in 1995 from the University of Bern, Switzerland and his PhD in Geology in 2001 from the University of British Columbia in Vancouver. From 2002 to 2009 he was a Lecturer and Senior Lecturer in Marine Geology/Sedimentology at the School of Earth and Environmental Sciences, James Cook University in Townsville, Australia. End of 2009, Raphael Wust joined Trican Geological Solutions Ltd. as a Technical Advisor in Calgary. He remains an Adjunct Senior Lecturer at James Cook University. Dr. Wust’s Ph.D work focused on sedimentary and geochemical comparisons between modern and past coal-forming inland basins. He is author and co-author of over 40 scientific papers and numerous field-guides and technical reports. He was involved and led several geological (including CBM) field trips/ studies in Australia, Indonesia, Malaysia and Panama. He has organized and run unconventional coal and shale gas/ oil geological short courses in Panama, Canada and Australia since 2000. His professional interests include organic geochemistry, marine geology, and modern and past sedimentary environments. He has completed several consulting projects in Egypt, Europe, Australia, Asia, and North America. Raphael Wust currently leads the AGAT Laboratories Study Group

which focuses on assessing regional unconventional targets including shales, tight silt- and sandstones. In addition, the group supports geological investigations of clients projects on shale oil/gas, tight gas and tight oil with a particular focus on: -Evaluation of thermal maturity and organic geochemistry; -Characterization of mineralogical, sedimentological and stratigraphic compositions of unconventional units; -Geological assessments of unconventional reservoirs/ source rocks including factors such as porosity, permeability, conductivity; -Rockfluid interactions including frac-water treatment and clay mineral interaction.

DIVISION INFORMATION BASS technical division talks are free. Please bring your lunch. For further information about our division, to join our mailing list, receive a list of upcoming talks, or if you wish to present a talk or lead a field trip, please contact either Steve Donaldson (BASS) at 403-808-8641, or Mark Caplan (BASS) at 403-975-7701, or visit our web page on the CSPG website at http://www.cspg.org. We would like to thank geoLOGIC Systems for sponsoring the new classroom, AGAT Laboratories for sponsoring refreshments and Belloy Petroleum Consulting Ltd. for sponsoring this technical division.

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DIVISION TALKS

GEOMODELLING DIVISION TALK Building a Provincial-Scale Geomodel of Alberta’s Subsurface: AGS’ 3D Provincial Geological Framework Model of Alberta SPEAKER Paulina Branscombe | Alberta Geological Survey (AGS) branch of the Alberta Energy Regulator (AER)

Time: 12:00 pm Date: Thursday, September 27, 2018 Location: Husky Conference Room A, 3rd Floor, +30 level, South Tower, 707 8th Ave SW, Calgary, Alberta ABSTRACT The Alberta Geological Survey (AGS) has constructed a provincial-scale threedimensional (3D) geological model of Alberta’s subsurface (excluding an area representing the approximate extent of Cordilleran deformation and the Rocky Mountains). The 3D Provincial Geological Framework Model of Alberta (3D PGF) represents AGS’ current provincial scale geological understanding and is based on decades of geological interpretation and conceptual models. The 3D PGF is an evergreen geological model that is constructed using a truly multi-disciplinary and iterative approach.

The current 3D PGF (Version 1) spans 602,825 km2 and includes 32 model zones extending from ground surface to an arbitrary flat base with the Precambrian (5000m below sea level) (Figure 1). The model was built using over 600,000 input data points largely from downhole geophysical log pick interpretations, outcrop data and resampled map lineaments.

Version 1 of the 3D PGF was published on Alberta Geological Survey’s website on May 4, 2018. The model is available via three deconstructed standard format digital data components (picks, model extents, model horizons), an iMOD 3D visualization bundle and a complimentary AGS Open File Report describing model methodology.

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AGS’ 3D geomodelling workflow will be presented as well as examples of complexity at working on a basin scale, issues with variable data distribution and learnings from provincial-scale model construction.

Additional recent AGS geological models, examples of physical 3D prints of AGS’ geological models and AGS model applications will also be discussed.

Figure 1. Oblique view of the 3D Provincial Geological Framework Model of Alberta (version 1) from the bedrock topography surface to the base of the model in the Precambrian. Transparent grey mass represents the Rocky Mountains and approximate deformation belt; vertical exaggeration = 40 x).

3D geological models can be used as single holistic geological foundations and can facilitate communication of subsurface characterization, hazard assessment and management of resources.

These models can also be used to support science-based decision making and inform regulatory decisions related to the safe and sustainable management of the Alberta’s resources.

BIOGRAPHY Paulina completed both her undergraduate geology and graduate geology degrees at the University of Alberta. Her M.Sc. (Geology) was on the geochemistry and evolution of fluids involved in the dolomitization and precipitation of metals and non-metal minerals at Pine Point lead-zinc mine in the Northwest Territories (a middle Devonian carbonate hosted deposit).

and unconventional plays) and their BP Anchorage (Alaska) office (heavy oil) for 9 years starting off in Operations and then focusing on Development/Appraisal.

She is an APEGA P.Geo. and is currently the “Manager, Geological Modelling” of a team of geoscientists, geomodellers, geostatisticians and engineers within the Alberta Geological Survey (AGS) branch of the Alberta Energy Regulator (AER).

DIVISION INFORMATION There is no charge for the division talk, and we welcome non-members of the CSPG. Please bring your lunch. For details or to present a talk in the future, please contact Weishan Ren, renws2009@gmail.com, or David Garner, David@terra-mod.com.

Her career started off in hard rock field geology but during the last oil boom (and mining bust) her career shifted to oil and gas. Paulina worked for BP Canada in their Calgary office (conventional

RESERVOIR ISSUE 5 • SEPTEMBER/OCTOBER 2018 36

DIVISION TALKS

OPERATIONS DIVISION TALK Proactive Geosteering with 3D Geo-models How Operations Teams Save on Capital and Improve Well Results SPEAKER Rocky Mottahedeh, P. Geol., P Eng. President, CEO United Oil & Gas Consulting and SMART4D Geosteering & Geomodelling Software

Time: 12:00 pm Date: Wednesday, September 26, 2018 Location: geoLOGIC Classroom (2nd Floor), Aquitaine Tower, 540-5th Avenue S.W. ABSTRACT Case studies will illustrate how advanced processes in geo-modelling, correlation facilities, automated 3D kriging, WITSML rig data aggregation, team-collaboration & real-time web-reporting processes improve horizontal well placements and save capital for operators. Delivery of the SMART4D Application whether cloud based or in networks allows complete real-time access of shared earth model and related realtime panels and views for all stakeholders.

This process saves time and resources for E&Ps. The 3D model based approach with over 1000 well’s experience is providing a path for consistent quality landings, lower doglegs, added formation accuracy, faster drilling, focused drilling in the sweet spots and less drilling issues. Apparent dip estimations extracted by the application and target planners that measure doglegs interactively when placed in the sweet spots ahead of the surveys reduce the actual doglegs.

Complex 3D model generation processes are simplified to single commands to regenerate structure maps, isopachs and property model in minutes. Operated by Geoscience professionals, the learning models become an integral part of their workflow, saving time in every aspect of their work for every well geosteered or upcoming well(s). The learning system

RESERVOIR ISSUE 5 • SEPTEMBER/OCTOBER 2018

panels cut through the driller plans with the updated structures and properties providing a view to the drill. Accurate placement also ensures that engineered wells in shale plays with multi-zone (bench drilling) potential are correctly placed for optimizing the completions and recovery.

There is a 25 year history of technology development behind SMART4D. It was developed to give an in-house technical advantage and was released in 2015 for E&Ps as a 3D mapping, modelling, well planning, geosteering, visualization & integration environment of G&G and drilling data. Team collaboration is the integral purpose in delivery of the real-time technology in networks and in the cloud.

Field services companies also recognizing the power of the 3D process they can run from rigs or anywhere.

SMART4D’s responsive 3D models are updated after correlations (within 3-5 minutes), the drilling corridor ahead of the surveys is continually updated using all offset data, all of the time. Model sizes can be very small to hundreds of wells. A proprietary 3D kriging engine is the key here where multiple structures, isopachs and property models such as gamma and porosity can run simultaneously.

The application is a workhorse in allowing for geosteering of multiple wells in multiple plays simultaneously. The process has worked for a single operator with 8 rigs concurrently. The Operator reduced rig days by 18%. A number of KPI’s shared by clients will be presented and discussed.

field development, the process has evolved from Heavy oil to Tight Oil & Shale plays with hundreds of wells.

BIOGRAPHY Rocky has over 35 years of Geology and Reservoir Engineering experience.

Graduated from Geological Engineering at University of Toronto in ‘81. In the early years he worked with TransCanada and PanCanadian. Through United, Rocky has worked with a large number of E&Ps in Canada, the US and internationally and develops SMART4D technology related to geosteering, geo-modelling and evaluation of infill potential using static and dynamic simulations.

The reservoir property models are also input for volumetric estimations and a Volumetric Sweep Mapping (VSM) simulator to model 3D drainage/footprint of horizontals in all resource types and fracs. at fraction of time of large simulators.

All aimed at saving capital and de-risking of

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DIVISION TALKS

OPERATIONS DIVISION TALK Regulating the Profession of Geoscience: some thoughts on the roles of governments, regulatory agencies, individual professionals, companies, and academia.

SPEAKER George Eynon, PGeo – geos • eynon associates

Time: 12:00 pm Date: Wednesday, October 10, 2018 Location: geoLOGIC Classroom (2nd Floor), Aquitaine Tower, 540-5th Avenue S.W. ABSTRACT The legislated purpose of regulating the professions of engineering and geoscience is the protection of the public. Although there is much emphasis on ethics and professionalism by the regulators of the professions, there is little on the relationships of the professional, financial or operational regulatory authorities, or between those agencies and academia.

Regulatory agencies rarely collaborate, and universities pay insufficient attention to ethics and professionalism in their curricula.

Licensed professionals have obvious conflicts between an obligation to clients and corporate shareholders on the one hand, and conducting operations in the public interest under a professional code of ethics on the other. Commonly, regulation of these two “masters” is in the hands of different agencies: in Alberta the principal ones are the Association of Professional Engineers and Geoscientists of Alberta (APEGA), the Alberta Energy Regulator (AER), and the Alberta Securities Commission (ASC). As well, academia and governments play a role in individual professionals’ working lives—and therefore in their ethical and professional conflicts.

A varied 45-year career in many jurisdictions affords a unique 360° view of the oil & gas industry and its professionals.

This, and the legal and ethical obligations

38

to which we as professionals must adhere, offer observations indicating a significant lack of effective collaboration among the various regulatory agencies and academia, which can create problems for Professional Geoscientists.

Broad experience: major, large, junior and start-up oil & gas companies; professional associations; regulatory agencies; education/research institutes; consulting firms.

BIOGRAPHY Managing Director & Principal Consultant with geos • eynon & associates consulting.

A seasoned executive and board member with 45 years’ professional practice in progressively senior technical, research, management, executive, board, and leadership roles in Canada, USA, Norway, Denmark, and several other countries.

Currently works with the University of Calgary’s School of Public Policy in its Extractive Resources Governance Program, as a Board member of CSUR, as an instructor for Oak Leaf Energy Training— and is President-elect of APEGA. Formerly, served as an ERCB Board Member and AER Hearing Commissioner.

T.I.H. Consulting Ltd. Geologic Well-Site Supervision

1602 – 5th St N.E. Calgary, AB. T2E 7W3 Phone: 403-233-7729 www.tihconsulting.com e-mail: tih@shaw.ca

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DIVISION TALKS

ALBERTA PALAEONTOLOGICAL SOCIETY DIVISION TALK Stromatolites of South Western Alberta Including Chief Mountain In addition to the main presentation by Dr. Terry Poulton, Barry Rogers will provide a brief presentation.

SPEAKER Barry Rogers has been a member of the Alberta Palaeontological Society for 15 years.

Time: 7:00 pm Date: Friday, September 21, 2018 Location: Mount Royal University, Room B108

other areas in southern Alberta and British Columbia. His talk will discuss their existence, the Lewis Thrust Fault and show pictures of these 1.4 billion old fossils on Big Chief Mountain, Waterton Lakes National Park, and in the Castle River drainage. Stromatolites are deposited by cyanobacteria and are confused by many as green algae. They took C02 from the air and combined it with calcium from the sea and are given credit for raising the oxygen levels that support our current environment.

BIOGRAPHY

ABSTRACT Barry first discovered Stromatolites in the rip rap on Waterton Dam during a club field trip. He has since found them in the Waterton/Glacier National Parks and in

Barry Rogers has a Degree in Agricultural Engineering from the University of Saskatchewan and a Masters Degree from The University of Stirling, Scotland where he met his wife Kate MacBeth. He has been

a member of the Alberta Palaeontological Society for 15 years and is a wannabe Geologist/ Rockhound.

DIVISION INFORMATION This event is presented jointly by the Alberta Palaeontological Society, the Department of Earth and Environmental Sciences at Mount Royal University, and the Paleontology Division of the Canadian Society of Petroleum Geologists. For details or to present a talk in the future, please contact CSPG Palaeontology Division Chair Jon Noad at jonnoad@hotmail.com or APS Coordinator Harold Whittaker at 403-286-0349 or contact programs1@ albertapaleo.org. Visit the APS website for confirmation of event times and upcoming speakers: http://www.albertapaleo.org/.

Call for Course Submittals!

The Spring Education Committee is collecting course proposals for Spring Education program.

To submit a course:

Go to www.cspg.org – Education– click on Submit a Course Download the form and submit the completed form to education@cspg.org

Course submittals will be accepted until noon on October 31st, 2018 Questions? Please email education@cspg.org

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DIVISION TALKS

ALBERTA PALAEONTOLOGICAL SOCIETY DIVISION TALK Ammonites witnessed the growth of Canada SPEAKER Dr. Terry Poulton, Geological Survey of Canada, Calgary

Time: 7:30 pm Date: Friday, September 21, 2018 Location: Mount Royal University, Room B108 ABSTRACT A major role of paleontologists in a geological organization is to interpret the age and depositional characteristics of sedimentary rocks as aids to mapping, sedimentary basin analysis, and resource exploration activities. Ammonites are of exceptional value for understanding Mesozoic marine strata because of the many morphological features they exhibit, their rapid evolution and the widespread distribution of many of them. During Jurassic time, North America was actively growing by accretion of oceanic terranes to its western margin; associated eastwest compression initiated the ancestral Rocky Mountains and affected the Western Canada Sedimentary Basin in the plains.

The Jurassic also saw the early stages of the opening of the western portion of the Arctic Ocean, and its precursor in the Sverdrup sedimentary basin in Canada’s Arctic archipelago. Since the earliest discoveries in Canada in the 1850’s, ammonites have enabled correlations of strata over long distances and provided precise ages by comparison of their sequences with the international standards, which have been mainly established in Europe. However, the identification of ammonites, and therefore the determination of their ages, is not always straightforward, in part because of the reappearance of superficially similar forms at different times and in different lineages.

Additionally, the occasional development of distinct marine faunal provinces was sometimes extreme, with few or no species in common with Europe at certain times during the Jurassic. This presentation will discuss some of the challenges and

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the geological contributions from several previous and on-going studies of Canadian Jurassic ammonites.

BIOGRAPHY After completing a B.Sc. at University of Calgary in geology (1968) and field experience with the Geological Survey of Canada (GSC) during the summers, Terry was offered an opportunity to study for an M.Sc., with University of Calgary professor Dr. Philip Simony to document the sedimentary sequence and paleoenvironments in Late Precambrian low-grade metamorphic rocks west of Golden, B.C. As this was being completed (1970), he also worked with PanArctic Oils Ltd, mapping and analyzing Mesozoic strata on western Ellesmere and Axel Heiberg Islands prior to the expansion of their hydrocarbon drilling program eastward from the discovery wells on Melville Island. By agreement, the fossils collected were studied by GSC’s longtime mollusc specialists Hans Frebold and George Jeletzky. Canada was still in the post-WWII growth spurt, and GSC was actively exploring its resource potential and terrane, which included large areas of Mesozoic sandstones, mudstones and

volcanics in the Arctic and the Cordillera frontiers. These strata of different ages are superficially similar, and unravelling them required knowledge of the ages derived from their fossils. To this end, GSC supported a Ph.D. project at Queens University, which led to a full-time job in early 1975 after Dr. Frebold retired. After years of undertaking specific research projects and contributions to several regional syntheses, as well as stints in lower and “middle” management in GSC, Terry continues to pursue topical research at GSC in Calgary.

INFORMATION This event is presented jointly by the Alberta Palaeontological Society, the Department of Earth and Environmental Sciences at Mount Royal University, and the Palaeontology Division of the Canadian Society of Petroleum Geologists. For details or to present a talk in the future, please contact CSPG Palaeontology Division Chair Jon Noad at jonnoad@hotmail.com or APS Coordinator Harold Whittaker at 403-2860349 or contact programs1@albertapaleo. org. Visit the APS website for confirmation of event times and upcoming speakers: http://www.albertapaleo.org/.

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DIVISION TALKS

ALBERTA PALAEONTOLOGICAL SOCIETY DIVISION TALK Ashfall Fossil Beds State Historical Park & National Natural Landmark Nebraska The ash (averaging one foot in depth) from this event blew into the hollow where a water hole was. Over time, the Ash Hollow Formation resulted, consisting of tan sandstone and grey-white ash, which varies in thickness from 3 to 5 feet. Captured in the ashbed, among other Pliocene critters, are fully articulated skeletons of rhinos Teleoceras major; camels Protolabis heterodontus; Procamelis grandis ; three toed horses Pseudhipparion gratum and one toed horses Pliohippus pernix.

In addition to the main presentation by Dr. Chad Morgan, Pete Truch will provide a brief presentation.

SPEAKER Pete Truch is an APS member and a retired ardent traveler

Time: 7:00 pm Date: Friday, October 19, 2018 Location: Mount Royal University, Room B108

Excavating and leaving the skeletal remains in situ resulted in a unique method of exposure within the confines of a large protective enclosed building. Thus, a visitor can see the bone beds and creatures exposed in their original mortuary poses, a number of which Pete will show in his summary presentation of a site visit made in 2017.

ABSTRACT The Yellowstone Hotspot (located in Yellowstone National Park) has produced five super-volcano calderas in the last 14 million years. The Bruneau-Jarbidge caldera resulting from the explosions of super-volcanoes between 12.5 and 10 million years ago have direct relevance to Ashfall, as this has been determined to be the source of the ash. Using single-crystal laser fusion Argon40/Argon 39 dating the tuff of the volcanic ash (with adjustment) yields a date of 11.93 million years. This one eruption is called the “Tuff of the Ibex Hollow”.

BIOGRAPHY Pete and his wife Doreen are ardent travelers. In 2010, they joined the ranks of famous circumnavigators of the globe (in a ship) including Captain Cook’s goat who surpassed them by having done it twice!

They have been on every ocean of the world (as Geographers have named them), although technically there is only one. In addition to having travelled to 68 countries, they have been in every jurisdictional part of Canada from Territories to Provinces, and now, with the visit to Ashfall Fossil Beds State Historical Park in Nebraska, have visited all 50 States.

DIVISION INFORMATION This event is presented jointly by the Alberta Palaeontological Society, the Department of Earth and Environmental Sciences at Mount Royal University, and the Paleontology Division of the Canadian Society of Petroleum Geologists. For details or to present a talk in the future, please contact CSPG Palaeontology Division Chair Jon Noad at jonnoad@hotmail.com or APS Coordinator Harold Whittaker at 403-2860349 or contact programs1@albertapaleo. org. Visit the APS website for confirmation of event times and upcoming speakers: http://www.albertapaleo.org/.

PASSIONATE.EVOLUTIONARY.PERFORMANCE .

1.306.291.1015

tyler@rockhoundadvisory.ca

Calgary & Saskatoon

WELLSITE GEOLOGY | GEOSTEERING | PROJECT MANAGEMENT

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DIVISION TALKS

ALBERTA PALAEONTOLOGICAL SOCIETY DIVISION TALK Highlights from the Middle Cambrian Stephen Formation SPEAKER Chad A. Morgan, Ph. D. Candidate, Department of Geoscience, University of Calgary, Calgary, Alberta

Time: 7:30 pm Date: Friday, October 19, 2018 Location: Mount Royal University, Room B108 ABSTRACT The Middle Cambrian Stephen Formation has a long and storied history in palaeontology. The formation originally included the famous Burgess Shale lagerstätten found in Yoho National Park by Charles Walcott in the early 20th century, and has subsequently become one of the most internationally recognised rock units in western Canada. During this talk an introduction to the historic background and the current cutting-edge science surrounding this formation will be discussed from Walcott to Franco Rasetti, to ongoing research at the University of Calgary. Results on trilobite taxonomic reassessments and biostratigraphic analyses for the formation will be presented

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as well as newly discovered fossils, including ~505 Ma bacterial filaments, and unusual geometric trace fossils found in the 'platformal' (formerly thin) Stephen Formation. Additionally, a brief introduction to an as of yet unpublished and newly discovered Burgess Shale fossil site in Yoho National Park, which has yielded a large number of Margaretia dorus specimens will also be presented.

This site with its large population of M. dorus specimens may aide in deciphering the taxonomic affinity of this problematic Burgess Shale fossil (whether they belong more closely with modern algae or are tubes constructed by hemichordate worms).

While the Cambrian may not always have the most impressive large fossils found in Alberta, this talk will hopefully reveal the amazing array of exciting science currently being undertaken and still left to be done on the half billion year old record found in western Canada.

BIOGRAPHY Chad Morgan is a PhD candidate in the Department of Geoscience at the University of Calgary. He is currently conducting research on trilobite biostratigraphy of

the Middle Cambrian Stephen Formation under the supervision of Dr. Charles Henderson and co-supervised by Dr. Brian Pratt (University of Saskatchewan).

His research has taken him to Burgess Shale fossil sites in Kootenay National Park as well as field sites in Yoho and Banff National Park. His research interests include invertebrate palaeontolgy, trilobite taxonomy, carbonate sedimentology, and ichnology.

DIVISION INFORMATION This event is presented jointly by the Alberta Palaeontological Society, the Department of Earth and Environmental Sciences at Mount Royal University, and the Paleontology Division of the Canadian Society of Petroleum Geologists. For details or to present a talk in the future, please contact CSPG Palaeontology Division Chair Jon Noad at jonnoad@hotmail.com or APS Coordinator Harold Whittaker at 403-2860349 or contact programs1@albertapaleo. org. Visit the APS website for confirmation of event times and upcoming speakers: http://www.albertapaleo.org/.

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DIVISION TALKS

CSPG STRUCTURAL DIVISION TALK Fracture characterization and vugular porosity distribution in Devonian carbonates using image logs and core data SPEAKERS Dragan Andjelkovic, Hakima Ali Lahmar, Gabriel Garcia Rosas (Schlumberger) Simona Costin & Becky Rogala (Imperial Oil Limited)

Time: 12:00 pm Date: Thursday, September 6th 2018 Location: Schlumberger Palliser One Building 200, 125 - 9th Ave SE, Calgary

Fracture intensity curves in the Elk Point Group show values between 10-20 fractures per metre. The average total vugular porosity (VISO) estimated from image logs is 2%, within certain discrete depth intervals, and can be attributed to the presence of connected vuggy areas and fractures. The heterogeneity analysis show that the base of the Keg River Formation is most suitable for water disposal. This talk presents the results within a regional context of fracture orientation and distribution within the Devonian.

BIOGRAPHY Dragan has been with Schlumberger Canada for 11 years working as a borehole geologist. His previous experience includes 10 years in the mining industry in Ontario and eastern Canada. He holds a masters in geology from the University of Belgrade.

Hakima has been with Schlumberger for 12 years working in various parts of the world, including Algeria, Kuwait and Canada. She holds an engineering degree in petroleum geology .

ABSTRACT Resistivity borehole images (FMI) were acquired in a series of wells drilled in the Devonian Elk Point and Beaverhill Lake Groups, in oil sands leases in NE Alberta.

The data were used for characterization of fractures and porosity systems in these formations, and in particular to identify zones suitable for water disposal. Since the images were of excellent quality, the geological data derived could be interpreted with a high level of confidence.

The borehole image analysis shows that the Keg River Formation contains substantial porosity heterogeneity, which varies spatially due to the presence of natural fractures and vugs. The objective of this study was to characterize and quantify this heterogeneity, using FMI images, and validate the results with core data (Fig 1).

Another aim of this study was to examine if fractures exhibit regional systematic trends, or if they are more localized and random.

Cross cutting relationships of the fracture sets and vugs were examined, in order to determine relative chronology of events.

Two main fracture cluster intervals were identified within the Keg River and Waterways Formations, dominated by partially open non-systematic fractures.

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Fig. 1. An example of partially open fractures and vuggy facies, as seen from both the FMI image and core.

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DIVISION TALKS

CSPG STRUCTURAL DIVISION TALK A Structural Excursion along the Rundle Thrust in the Front Ranges, Canmore, Alberta SPEAKERS Francois Tremblay (P.Geo) & Leena Markatchev (Geologist), with contributions from Dr Gerry Reinson (Consultant)

Time: 12:00 pm Date: Thursday, October 4th 2018 Location: Schlumberger Palliser One Building 200, 125 - 9th Ave SE, Calgary ABSTRACT This talk will present a review and discussion of the Structural Division Field Trip, to be held in the Front Ranges (Figure 1) in Canmore on Saturday September 22nd, 2018 (see www.cspg.org/structural).

Coal seams from the Cretaceous Kootenay Formation were exploited in Canmore from 1887 to 1979. These footwall shales and coals were plastically deformed into tight and often overturned structures within the broad Mount Allan Syncline that runs through the Bow Valley Corridor. Perhaps overlooked, structurally higher, within the Rundle Thrust Sheet, spectacular structures in the Devonian, Mississippian and Permian section are present in the hanging wall zone.

This presentation highlights features visited in the field trip, including exposures of the Rundle Thrust, and major structures

(Figure 2) such as classic fault-propagation folds and their structural fabric (Figure 3) that are otherwise hidden from roads. We will give a virtual tour of the 2 traverses from the trip.

The rock units encountered are ageequivalent to known hydrocarbon reservoirs in the Foothills and Alberta Plains, and have had a profound impact on shaping the economic landscape of Alberta.

Figure 1: Subdivision of Canadian Rockies into three belts. Red star shows location of field trip (adapted from McMechan and Macey, 2012).

Interesting comparisons will be made between our tour and previous large-scale mapping carried out in the area.

Another objective of the talk is to emphasize the variety of scales of structures encountered and comparing them to world-class commercial discoveries in Canada and internationally.

REFERENCE: McMechan, M., Macey, E., 2012. Geology of the Rocky Mountains west of Calgary, Alberta in the Kananaskis west half map area (82J). Paper presented to CSPG/CSEG/ CWLS GeoConvention 2012, Calgary, Alberta, 14-18 May 2012.

BIOGRAPHY Francois Tremblay holds a B.Sc. degree (Hon.) in Geology from the University of Calgary and a M.Sc. in Geophysics from Leeds, United Kingdom. He is a

Figure 3: Stereonet of bedding, fractures and a weak cleavage in the Palliser Formation in the field trip area. professional geoscientist with over 10 years of experience in exploration and development. He has worked exploration in North America, South America, Europe, Africa and Asia Pacific. He currently works as an exploration geophysicist on projects across Australasia.

Leena Markatchev has a B.Sc. degree (Hon.) in Geology from the University of Calgary and a M.Sc. from the University of Ottawa. She has worked for 7 years in the exploration and development of the Williston and Western Canada Sedimentary Basins.

Figure 2:View looking southeast of an anticline in the Fairholme Group.

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RESERVOIR ISSUE 5 • SEPTEMBER/OCTOBER 2018

Stanley Slipper Medal Call for Nominations “This pioneer and explorer in geology, engineering and natural gas technology bequeathed a fundamental knowledge, years ahead of his time and was considered by many a virtual Leonardo da Vinci of the Petroleum Industry. Slipper, our First President, deserved the honour (unbeknownst to him) of our highest award in the Canadian Society of Petroleum Geologists” - Aubrey Kerr The Stanley Slipper Medal is amongst the CSPG’s Highest Honours.

The medal is presented annually for outstanding contributions to petroleum exploration and development either in Canada or by Canadian-based petroleum geologists working internationally. The contributions of the winner of this award may encompass one or more activities including initiating and/or leading exploration or development programs, making significant discoveries on new or existing exploration trends, applying new technologies to exploration and exploitation, and teaching and/or training of petroleum geologists. In contrast to other CSPG awards, the Stanley Slipper Award recognizes, in part, accomplishments in business and in the broader petroleum industry through the application of the knowledge of petroleum geology. The award is limited to individuals. Candidates must be alive at the time of their selection. The winner must be a petroleum geologist and a CSPG member.

The committee is currently calling on the CSPG membership to provide nominations for this prestigious award.

2017 Stanley Slipper Recipient

Alison Essery

Please include an updated biography and letters in support of your nominee. It is recommended that potential nominations be vetted with the Committee Chair early in the process in order to avoid, if possible, duplicate nominations for the same person. Please consult the Career Achievement Awards section of the website for additional requirements and expectations related to the nomination process.

Nominations should be mailed or emailed before October 12 to:

CSPG Stanley Slipper Committee – Clinton Tippett 150, 540 – 5 Ave SW Calgary, AB T2P 0M2 Email: clintontippett88@gmail.com

Stanley Slipper Medal RESERVOIR ISSUE 5 • SEPTEMBER/OCTOBER 2018

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SOCIETY NEWS

TIME TO DISCUSS ADVANCES IN THE ROCK ANALYSIS OF HETEROGENEOUS RESERVOIRS R.A.W 2019 Planning Committee: Amin Ghanizadeh – University of Calgary, Stan Stancliffe – Independent Consultant, David Robertson – Schlumberger Reservoir Laboratories, Ken Glover- Trican Well Service

T

ight rock and oilsand reservoirs are currently the hottest unconventional resource targets in western Canada.

These reservoirs are heterogeneous geological systems with variations in composition and fabric existing from the micro- up to the macro-scale, depending on their bitumen and total organic carbon (TOC) content, thermal maturity, mineralogical composition and diagenetic history. The impacts of these lithological factors on hydrocarbon storage and transport properties of these reservoirs are, however, rock-specific and are not necessarily similar among all plays. The micro-structure of these reservoirs, in particular, can differ significantly between different formations and even within the same play/area. Within the matrix system of these unconventional reservoirs, hydrocarbon storage capacity is partly controlled by “in-situ” water saturations, pore volume, surface area (e.g. for hydrocarbon (ad)(ab)sorption), and pore size distribution whereas pore throat size distribution, tortuosity, pore connectivity, permeability and wettability attributes influence long-term production.

Mechanical characterization of tight rock and oilsand reservoirs is further an important step in the evaluation and completion of these unconventional reservoirs. Combined with the field-scale geological features and the ‘‘in-situ’’ stress regimes, the geomechanical properties of these unconventional reservoirs play a key role in planning of drilling, completion and hydraulic fracturing practices.

Knowledge of geochemical, petrophysical

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and geomechanical characteristics of these reservoirs and their relationship with the controlling lithological factors are, therefore, fundamental to the quantification and prediction of hydrocarbons-in-place and production in these resources.

Economic flow rates in tight oil and gas plays, which commonly have permeability values down to the nanodarcy range, are governed by a complex series of multiscale physico-chemical processes within space and time throughout the fracture and matrix systems. This is also true when analyzing the quality of cap rock over an oil sands reservoir.

Routine core analysis techniques, primarily developed for conventional reservoirs with comparatively higher porosity/ permeability and less complexities, may not be fully applicable to tight rock reservoirs or cap rock investigations, failing to provide a realistic understanding of fluid storage, potential barriers and flow mechanisms that occur during fieldscale production. In the face of ongoing suppressed commodity prices, the energy industry seeks innovative core and cuttings analysis techniques that allow reliable, fast, inexpensive and efficient identification of reservoir “sweet spots” and provide critical data for assessing exploration, completion and hydrocarbon recovery strategies to produce hydrocarbons more efficiently. Understanding how to advance characterization methods at all scales is therefore critical for predictable development through primary and

enhanced recovery processes.

The Rock Analysis Workshop (R.A.W.) will bring together professionals and subject matter experts, dealing with multidisciplinary characterization of unconventional and bitumen reservoirs, to share experiences gained through laboratory and field operations.

The workshop will focus on new advances in rock characterization and the added value of field applications. A variety of leading operators, service providers, and national/international universities will provide up-to-date discussions on multiple technical topics. These include highlights on advanced geochemical, petrophysical and geomechanical characterization techniques, case studies, and operator and governmental regulatory perspectives.

A dedicated panel session will explore potentials for collaboration among operators, technology developers, service providers and governmental regulatory agencies.

The Canadian Society of Petroleum Geologists (CSPG) and technical committee are currently soliciting speakers and presenters for this event (invitation-based only) and thank all of the invited speakers in advance for their valuable and insightful contribution. For further information on workshop registration, agenda, accommodation and sponsorships, please visit the event’s website or contact Candace Jones at candace.jones@cspg.org. Looking forward to meeting you all in R.A.W. 2019!

RESERVOIR ISSUE 5 • SEPTEMBER/OCTOBER 2018

2018 Ph.D. and M.Sc. CALL FOR THESES Ph.D. AWARD Win $5,000, a framed certificate, and a one-year CSPG membership for the Doctoral thesis that makes the most significant contribution to Canadian sedimentary geology in 2018.

M.Sc. AWARD Win $4,000, a framed certificate, and a one-year CSPG membership for the Masters thesis that makes the most significant contribution to Canadian sedimentary geology in 2018.

Winning thesis in recent years have included: A study which developed a new and robust method of interpreting complex tidal successions using the Bluesky-Gething interval in the Peace River area as the study area; a field based outcrop study of the Lower Lajas Formation in the Neuquen Basin of west-central Argentina; a detailed stratigraphic, sedimentological and geochemical study of the mudstone dominated Carlile Formation in Eastern Alberta with a focus on advancing the model for the deposition of mudstones; a sedimentological and neoichnological examination of a modern mixed energy estuary at Tillamook Bay on the coast of Oregon; a re-interpretation of the classic Silurian reefs in Southern Ontario and Michigan; an integrated analysis of the evolution of the passive continental margin off the coast of Nova Scotia incorporating the extensive seismic data set acquired over the last 25 years; and evaporate diapirism in the Canadian Arctic Archipelago.

DEADLINE FOR SUBMISSIONS IS SEPTEMBER 28, 2018 For submission, an electronic copy (.pdf format) of the thesis is preferred but a hard copy, if properly bound, will be accepted. Submitted hard-copy theses will be returned in late January 2019.

Eligible theses are either produced in a Canadian university, regardless of project location, or deal with a Canadian sedimentary/petroleum geology topic, regardless of the university of origin. Theses entered for the 2018 awards must have been submitted to a recognized university inside or outside of Canada and must have formed part of the requirements for degrees awarded at the Fall 2017 or Spring 2018 convocations.

Candidates theses must be well written and clearly and adequately illustrated

Please submit electronic copy of thesis for judging to: Canadian Society of Petroleum Geologists (CSPG) Graduate Thesis Awards Committee

c/o Andre Chow amcchow@gmail.com For submission of a hard copy thesis or additional information please contact Andre Chow at the above email or tel: 587-777-2154

Clastic Exploration School October 22-26, 2018, Calgary, Alberta Instructors: David James, Jim Barclay & Andy Vogan Member rate: $2500

Non-Member rate: $2700

Note from the Instructor(s): After a three + decade run, David decided to wind down the school at the close of the October 2017 CSPG class. But as famously stated “There are strange things done in the midnight sun” and that James is back could be one of them. That is because Jim and Andy, together with the CSPG unexpectedly stepped forward, and offered to continue the legacy of the class into the future. It is our hope, that with a cumulated exploration experience of the instructors boosted to well over 100 years, that the class will provide benefits to geoscientists, explorationists and to the CSPG for years to come.

Course Overview

This five-day school has been taught to Calgary, Houston and internationally based geologists and geophysicists for over 30 years and was initially designed as a mandatory course for all junior staff.

Over the years it became apparent that more senior G/G (and Engineers) could gain great benefit from re-examining the advances made in facies modeling, traces fossils, sequence stratigraphy and seismic geomorphology. Using a combination of lectures followed by core examination, all clastic depositional settings from the Western Canadian basin that contain hydrocarbons are discussed.

Emphasis will be placed on core description, identifying sedimentary structures, recognizing reservoir facies, sequence boundaries, flooding surfaces and most importantly, thinking geologically. Delegates will be exposed to a vast amount of core (600+ boxes) over 5 days. The ultimate product is the establishment of a robust stratigraphically and facies based exploration model to guide a drilling program. Core correlation and field based exercises with data sets from the Alberta Basin and the international arena will be used to reinforce the concepts. The school concludes with a lecture on the controls of reservoir quality and how they relate to depositional setting and well productivity.

For instructor biographies and more course information please go to

www.cspg.org David James

Jim Barclay

Andy Vogan