The difference between raw data and refined information?
Focus, quality and value. We don’t build our reputation on volumes—instead, we earn it on the quality of the information we extract from that data. For more than 75 years, IHS has processed and analyzed vast amounts of raw data, concentrating it into the in-depth, actionable information that is used today to advance energy-critical business decisions. Energy information, refined.
Technical Programs and Social Events Coordinator: Dayna Rhoads
Email: dayna.rhoads@cspg.org
Convention Contacts:
Convention Manager: Aileen Lozie
Email: aileen.lozie@cspg.org
EDITORS/AUTHORS
Please submit RESERVOIR articles to the CSPG office. Submission deadline is the 23rd day of the month, two months prior to issue date. (e.g., January 23 for the March issue).
To publish an article, the CSPG requires digital copies of the document. Text should be in Microsoft Word format and illustrations should be in TIFF format at 300 dpi., at final size. For additional information on manuscript preparation, refer to the Guidelines for Authors published in the CSPG Bulletin or contact the editor.
Technical Editors
Ben McKenzie Colin Yeo (Assistant Tech. Editor) Tarheel Exploration EnCana Corporation
Advertising inquiries should be directed to Caitlin Young, Tel: 403-513-1227, email: caitlin.young@cspg.org. The deadline to reserve advertising space is the 23rd day of the month, two months prior to issue date.
The RESERVOIR is published 11 times per year by the Canadian Society of Petroleum Geologists. This includes a combined issue for the months of July and August. 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. Additional information on the RESERVOIR’s submission guidelines can be found at http://www.cspg.
FRONT COVER Exshaw Shale, Kananaskis, Alberta. Winner, Best Macro.
On behalf of all Members I thank John Varsek and Graeme Bloy and their Executives for their many accomplishments. The result is a strong CSPG characterized by passionate and motivated volunteers. We can justly celebrate our program – including our globally recognized Technical Luncheons, our Division meetings, our publications, and our Joint Annual Convention. Ensure that you participate in “recovery 2011” http://www.geoconvention.com/, which is striving to be a supernova in a constellation of previous stellar events. Recent progress has revitalized our continuing education offerings and field trips, improved our communications, and provided both engaging social events and a diverse scientific outreach p rogram. We thank our office staff, led by Lis Bjeld, for their dedication and assistance, but the most important reason for our success is you, our member volunteers. Thank you all for both your contributions and participation.
Continuing Executive Committee members (http://www.cspg.org/contact/contactcommittees-executive.cfm) welcome the incoming members, including: Robin Mann (Vice-President), Andrea Hood (Finance), John Noad (Program), Simon Haynes (Outreach), and Chris Seibel and Michelle Hawke (Services). We also thank Mark Cooper for standing for election as VicePresident following unparalleled volunteer contributions to the CSPG. Directors and Officers are also members, and many are chosen because of previous Event, Division, Committee or Convention service. The Executive sees our role as facilitating the work of you, the member. To that end, much work this year will focus on realizing the revitalization vision initiated last year. Several initiatives in the program, education, and communications portfolios
will take several years to realize and the current and future Executives must “stay the course” to ensure their success.
The revitalization program also identified several Executive priorities to ensure the mechanisms of the Society serve better its members and the value they derive from participating. Key among these is the cost, location, visibility, and accessibility of the Office. It is our goal to either move or renovate the Office to increase its visibility and accessibility, following the 2011 Convention. We seek to better serve you, the Members, without increasing our Administrative costs. Expect the office to be physically smaller, but better located and more accessible.
Recent experiences also indicate that volunteers will be better served by more effectively communicated policies and best practises. All of our volunteers are well motivated and goal-oriented, but we need to ensure your visions and initiatives are achieved in a safe and sustainable manner. There is a gre at benefit to delegating both responsibilities and authorities – to empower the members – but this requires that our volunteers clearly understand policies and best-practises, and why these guidelines are in place. I am sure we can all agree that it is important that we protect our members and their interests, while ensuring the integrity, strength, and future of the Society. We must also guard that no particular interest takes advantage of either the Society’s resources or reputation at the expense of the general membership’s best interest. To this end, we will be working to ensure that policies and procedures are easily and transparently available directly to volunteers using an
(Continued on page 7...)
UPCOMING EDUCATION SCHEDULE
Field Seminars
Modern Terrigenous Clastic Depositional Systems April 27-May 4
South Carolina
Clastic Reservoir Facies and Sequence Stratigraphic Analysis of Alluvial-Plain, Shoreface, April 30-May 6
Deltaic, and Shelf Depositional Systems
Utah
Complex Carbonates Reservoirs: Sedimentation and Tectonic Processes
Italy
May 8-14
Play Concepts and Controls on Porosity in Carbonate Reservoir Analogs May 15-20
Spain
Folding, Thrusting and Syntectonic Sedimentation: Perspectives from Classic Localities of the June 6-10 Central Pyrenees
Spain
Lacustrine Basin Exploration
Utah
June 19-26
Northern Appalachian Basin Faults, Fractures and Tectonics And Their Effects On The Utica, June 20-24
Geneseo And Marcellus Black Shales
New York
Short Courses
First Annual Summer Education Conference
June 6-10 Fort Worth, Texas
Fractured Reservoirs: From Geologic Concepts To Reservoir Models June 18-23 Casper, Wyoming
Last Chance
E-Symposium: Siliciclastic Sequence Stratigraphy: Application to Exploration and Production February 17 Online 2:00 p.m., CST
Winter Education Conference February 28-March 4
Houston
CORPORATE SPONSORS
AAPG
AGAT LABORATORIES
APACHE CANADA LTD.
APEGGA
ARC FINANCIAL CORPORATION
ARYTON CONSULTING ExPLORATION LTD
BAKER ATLAS
BLUEBACK RESERVOIR
BOYD PETROSEARCH
CANADA BROKERLINK
CANADIAN NATURAL RESOURCES LTD
CASEY & ASSOCIATES
CENOVUS ENERGY INC.
CGG VERITAS
COLORADO SCHOOL OF MINES
CONOCOPHILLIPS CANADA LIMITED
DEVON CANADA CORPORATION
DIVESTCO INC.
ENCANA
ENERPLUS RESOURCES FUND
FUGRO AIRBORNE SURVEYS CORP.
FUGRO – JASON
GEOEDGES INC.
geoLOGIC systems ltd.
GEOMODELING TECHNOLOGY CORP.
GEOSTRATA RESOURCES INC.
HALLIBURTON ENERGY SERVICES
HUNT OIL COMPANY OF CANADA
HUSKY ENERGY INC.
IHS
IMPERIAL OIL RESOURCES
LARIO OIL & GAS COMPANY
LITTLE ROCK DOCUMENT SERVICES
LORING TARCORE LABS LTD.
MJ SYSTEMS
MURPHY OIL COMPANY
NEURALOG
NExEN INC.
PENN WEST ENERGY TRUST
PETROCRAFT PRODUCTS LTD.
PLUSPETROL
PROVIDENT ENERGY LTD.
RPS ENERGY
SCHLUMBERGER CANADA LTD.
SENSOR GEOPHYSICAL LTD.
SHELL CANADA LIMITED
SPROULE ASSOCIATES LIMITED
SUNCOR ENERGY INC.
TALISMAN ENERGY
TOTAL E&P CANADA LIMITED
TOURMALINE OIL CORP.
TUCKER WIRELINE LTD.
WEATHERFORD LABORATORIES
AS OF JANUARY
(...Continued from page 5)
information session provided by the PastPresident and through our revamped website. Currently our by-laws and policies are very supportive of diverse activities. Please ensure that you check with the responsible Director, the Staff, and the website to achieve your goals in an aligned, facile, and approved manner. To this end, you should now find the CSPG “Committee Approval Request Form” on the website. It shows efficiently who you need consult with or seek approval from to accomplish your initiatives. We are also working on upgrading the website calendar so that you will know reporting and approval requirements. All this efficiently and effectively helps us to delegate both responsibilities and authorities to you.
The E xecutive also has a responsibility to ensure that our by-laws and corporate instruments are aligned to the vision of our founders, flexible enough to respond to our changing work and business environments, and sufficiently forward-
looking so as to ensure our future success. To this end, we shall begin the process of modernizing our by-laws and governance with the goal of retaining our past strengths, facilitating membership value, and positioning the Society to remain an internationally recognized and nationally leading Canadian geoscience organization. The Executive will seek and needs to hear your vision, so be prepared to respond when we ask.
Our past success including the global and national prestige of our Society was the product of our Members. As members, the Executive will work with you and the office to ensure that we provide you good value, engaging programs, and a Society in which you can take pride. We have “punched above our weight” in the past and I am confident that we will continue to provide both national and global scientific leadership in the future because of Members’ effort and dedication. Thank you.
technicaL Luncheons FEBRUARY LUNCHEON
Consequences of multiple phases of Tertiary uplift and erosion on the thermal evolution of Mesozoic source rocks, North Slope – Chukchi Sea,
Alaska
SPEAKER
Scott A. Barboza
ExxonMobil
Upstream Research Company
Funded by the AAPG Foundation
HUGH REID’S
11:30 am
t hursday, February 10, 2011 c algary, te L us c onvention c entre c algary, a lberta
Please note: the cut-off date for ticket sales is 1:00 pm, monday, February 7, 2011. csPg member ticket Price: $42.00 + gst. nonmember ticket Price: $45.00 + gst.
Each CSPG Technical Luncheon is 1 APEGGA PDH credit. Tickets may be purchased online at https://www.cspg.org/eSeries/source/ Events/index.cfm.
The Brookian sequence of the North Slope - Beaufort Sea - Chukchi Sea area of Alaska comprises more than 7.5 km of Lower Cretaceous to Holocene clastics representing Brookian foredeep deposition. Northward advancement of Tertiary Stage II Brookian contraction resulted in basementinvolved thrusting across the North Slope of Alaska, causing uplift and exposure of the Brookian sequence. A regional 3D basin simulation illustrates the effect of uplift on the timing of hydrocarbon generation. The amount and timing of erosion were incorporated by constructing removedsection maps constrained by integrating thermal maturity and apatite fission-track data from wells with shale velocity data from seismic. These data suggest that, at least, two erosional episodes removed up to 3km of sediment. Paleogene erosion was focused along the Brookian foothills and the Meade Arch. The northeastward migration of the Paleocene shoreline records the loss of accommodation space due to the effects of uplift and sedimentation. Neogene erosion was restricted to the Chukchi Sea. The basin simulations suggest that initial hydrocarbon generation from Mesozoic source rocks took place during the Upper Jurassic. Peak generation was coincident with Brookian foredeep deposition during the Middle Cretaceous and the generation window migrated northward during foredeep subsidence. Most generation ceased during the Upper Cretaceous, although Tertiary generation follows the northeastward migration of the Paleocene shoreline. Recent generation is restricted to
Webcasts sponsored by
the Neogene depocenter near the outlet of the modern Colville River.
BIOGRAPHY
Scott A. Barboza
Education:
Ph.D. Geology, University of Washington
M.S. Geology, University of Washington
B.S. Geology, University of California at Davis
Experience:
• 11 years with ExxonMobil as a research scientist and team leader
• Expertise in hydrocarbon systems analysis, basin modeling, basin analysis, computational fluid dynamics
• Regional evaluations of basins in North and South America, Africa, Europe, the Middle East, and Russia
• Nine scientific publications and numerous presentations
Selected Publications
Barboza, S.A., Alway, R., Akpulat, T., Esch, W.L., Hicks Jr., P.J., and Gerdes, M.L. 2010. Stochastic evaluation of fluvial to marginal marine sealing facies. Marine and Petroleum Geology v. 4, p. 445-456.
Isaksen, G.H., Aliyev, A., Barboza, S.A., Puls, D., Guliyev, I. 2007. Regional evaluation of source rock quality in Azerbaijan from the geochemistry of organic-rich rocks in mudvolcano ejecta. In: Oil and Gas of the Greater Caspian Area. P.O. Yilmaz and G.H. Isaksen (eds.). AAPG Studies in Geology 55, p. 51-64.
Barboza, S.A. and Boettcher, S.S. 2000. Major and trace element constraints on fluid origin, eastern offshore Trinidad. Proceedings GSTT 2000 Society of Petroleum Engineers TG103, p. 1-11.
Research Interests
Dr. Barboza’s research spans the fields of geomechanics, transport theory, hydrocarbon phase equilibria, geostatistics, geochemistry, and petrology. He has applied these interests to understanding the physics of hydrocarbon migration and the pressure/temperature evolution of sedimentary basins. Dr Barboza’s work uses a range of analytical and modeling techniques, and is built upon the multi-disciplinary integration of observations. A key philosophical underpinning of his work is the recognition and propagation of uncertainty in data, analyses, and simulation results. Scott is an avid cyclist and orchid aficionado. He lives in Houston, Texas, with his wife, Margaret, and children, Danielle, Alexandra, Olivia, and William.
technicaL Luncheons FEBRUARY LUNCHEON
Examination of potential factors affecting successful exploration and production of Devonian Marcellus Shale gas, eastern United States
SPEAKER
James L. Coleman Jr. U. S. Geological Survey, Reston, VA Funded by the AAPG Foundation
11:30 am
tuesday, February 22, 2011 calgary teLus convention centre calgary, alberta
Please note: the cut-off date for ticket sales is 1:00 pm, Wednesday, February 16, 2011. csPg member ticket Price: $42.00 + gst. non-member ticket Price: $45.00 + gst.
Each CSPG Technical Luncheon is 1 APEGGA PDH credit. Tickets may be purchased online at https:// www.cspg.org/eSeries/source/Events/index.cfm.
The Devonian Marcellus Shale is one of several, very-high-profile shale gas plays in the United States and is the most significant new play in the Appalachian Basin in several decades. The following key factors will probably determine whether or not this play will develop into a natural gas resource that meets national expectations:
(1) The volume of economically extractable resources. Assessments of the amount of undiscovered, technically recoverable gas vary and depend on the effectiveness of horizontal drilling and multi-stage
hydraulic fracture stimulation. Estimates of undiscovered, technically recoverable natural gas range from 0.8 to 3.7 trillion cubic feet by the U. S. Geological Survey (USGS) in 2002 to more than 100 times these amounts by industry consultants in 2008.
(2) The availability of sufficient fresh water for drilling, stimulation, and completion of the wells. Current shale gas well designs call for use of three to nine million gallons of fresh water per well to attempt a successful completion. Given the number of forecasted wells necessary to extract the resource, there is concern that there will not be enough fresh water available for the work.
(3) The capacity for effective disposal or reclamation of post-completion drilling and completion fluids and solids. All of the material pumped into the reservoir that is recovered back to the surface must be disposed or recycled. Currently, there is inadequate capacity to handle this flow-back material properly at the scale planned for full development.
(4) The potential for significant wildlife habitat fragmentation caused by drill-pad density and gathering, compression, and pipeline facilities. In areas of large, contiguous habitat, the activities associated with well-site construction, maintenance, and production activities may produce unintended consequences with respect to forest health and invasive species.
With collaborators, the USGS is studying the relative importance of these factors and the role they may play in the evolution of the Marcellus Shale gas play so that we can meet our mission obligation to improve the nation’s understanding of ecosystems and resources. Proper and prudent planning with foresight to managing the entire natural resource base will be necessary if the Marcellus shale gas play will reach its stated potential. The first steps in this planning effort involve examining and understanding the baseline conditions of these four factors.
BIOGRAPHY
Jim Coleman is the Director of the Eastern Energy Resources Science Center, U. S. Geological Survey (USGS), which conducts research and resource assessments on fossil fuel resources and examines the effects of their presence and use on human health and the environment. At the USGS, he has continued his research on unconventional gas systems and oil and gas resource assessments in
Webcasts sponsored by
the Appalachian, Gulf of Mexico, and ArkomaOuachita Basins. Before joining the USGS in 2003, Jim worked for 25 years with Amoco and BP on a variety of international and domestic oil and gas exploration and production and produced water management projects.
Jim has published articles on unconventional gas reservoirs, oil and gas resource assessments, basin and petroleum system evolution, deep water sandstone deposition and reservoir development, thrust- and fold-belt structural geology and petroleum accumulations, and carbonate sedimentology. His work comparing the American Petroleum Industry with the American Whale Oil Industry was recognized with the best presentation award for his talk at the Energy Minerals Division session at the 1994 Denver AAPG annual meeting. He received an M.S. in geology from Mississippi State University in 1978. He lives in Sterling, Virginia, with his wife Jane.
Recent publications relevant to lectures: Coleman Jr., J. L. 2008. Tight-gas sandstone reservoirs: 25 years of searching for ‘‘the answer’’. In: Understanding, exploring, and developing tight-gas sands. S. P. Cumella, K.W. Shanley, and W. K. Camp (eds.). 2005 Vail Hedberg Conference. American Association of Petroleum Geologists Hedberg Series, no. 3, p. 221-250.
Coleman, J. 2009. Tight-gas sandstone reservoirs: the 200-year path from unconventional to conventional gas resource and beyond: In Unconventional energy resources: making the unconventional conventional. T. Carr, T. D’Agostino, W. Ambrose, J. Pashin, and N. C. Rosen (eds.). 29th Annual GCSSEPM Foundation Bob F. Perkins Research Conference, December 6-8, 2009, Houston, TX, Proceedings CD, p. 397-441.
Coleman, J. L. and Swezey, C. S. 2009. Examination of potential factors affecting successful exploration and production of Devonian Marcellus Shale gas, eastern United States (abstract). 2009 American Association of Petroleum Geologists Annual Convention and Exhibition, Denver, Colorado, June 7-10, 2009. AAPG Search and Discovery Article #90090. http://www.searchanddiscovery.net/ abstracts/html/2009/ annual/abstracts/coleman. htm.
technicaL Luncheons MARCH LUNCHEON
Important characteristics of Rocky Mountain tight gas accumulations
SPEAKER
Stephen P. Cumella Bill Barrett Corporation
Funded by the AAPG Foundation 11:30 am Wednesday, march 2, 2011 calgary, teLus convention centre calgary, alberta
Please note: the cut-off date for ticket sales is 1:00 pm, Friday, February 25, 2011. csPg member ticket Price: $42.00 + gst. non- member ticket Price: $45.00 + gst.
Each CSPG Technical Luncheon is 1 APEGGA PDH credit.
Did you know that you can book a table for the Technical Luncheon? To book your company’s table or to buy tickets, visit http://www.cspg. org/events/events-luncheons.cfm.
Sandstones in tight gas accumulations in the Rocky Mountains commonly have permeabilities in the single-digit microdarcy range and water saturations below 50%. If these sandstones had similar permeabilities at the time they were gas charged, capillary pressures required to reach these water saturations would have been hundreds to thousands of psi. Buoyancy can create these high capillary pressures, but gas columns must be hundreds to thousands of feet to reach these pressures. Many Rocky Mountain tight gas accumulations occur in discontinuous fluvial sandstone intervals where fluid columns of this magnitude aren’t possible. An alternative explanation for this problem is that the gas charge occurred before the sandstones reached
very low permeability when the capillary forces required to reach low water saturations were much lower (Shanley et al., 2004). This explanation proposes that gas charge occurs at shallower burial depths and compaction and cementation degrade permeability to the microdarcy range with continued burial.
Recent studies of the diagenesis of Mesaverde sandstones in the Piceance Basin indicate that permeabilities were reduced to n ear their current microdarcy levels prior to or during gas charge. Two mechanisms to provide the high capillary pressures required to charge the tight sandstones other than buoyancy are gas generation from in situ coals or other organic-rich intervals and gas migration up major fault and fracture zones from highly pressured organic-rich underlying units. These deeper units are probably also overpressured as a result of hydrocarbon generation. Significant in situ organic content is required to saturate the pore space of the sandstones in a tight gas accumulation. Some tight gas systems such as the southern Piceance may have sufficient in situ TOC to charge the sandstones within the system. Such systems have commercial production at high well density over large areas of the basin. Basins like the Piceance or the San Juan either have (San Juan) or will have (Piceance) continuous producing areas in most of the deeper parts of the basins.
Tight gas systems with low in situ TOC have a much more limited distribution of commercial gas production. Some tight gas accumulations may be conventional traps with gas/water contacts that are obscured by the very low relative permeability to gas or water (Shanley et al., 2004) Other tight gas accumulations may be controlled not by trap but by proximity to a major fault system that provides a conduit for highly pressured gas from deeper formations.
High heat flow may also be critical to creation of pervasive highly gas charged accumulations. The importance of high heat flow is indicated by significant differences between the Williams Fork gas accumulation in the north and south parts the Piceance Basin. In the southern Piceance, the gas accumulation has uniformly low water saturations, low water production, and a gas-saturated interval that gradually t hickens into the deeper part of the basin, but the top of the gas interval shows little variation locally. In the northern part of
Webcasts sponsored by
the basin, the gas accumulation has variable water saturation, higher water production, and the top of the gas-saturated interval can vary significantly over relatively short distances. The higher heat flow in the southern Piceance may have created a pervasive fracture system that allowed all sandstones within the gas-saturated interval to be charged to high gas saturations. In the northern Piceance, gas migration may have occurred primarily along major fracture and fault zones; areas near the fault zones have better gas saturations and thicker gas-saturated intervals. Prolific tight gas accumulations in the San Juan Basin and in Wattenberg field in the DJ Basin are other examples in which high heat flow may have played a significant role in the creation of the accumulation.
BIOGRAPHY
Stephen P. Cumella is a geologist with Bill Barrett Corporation in Denver, Colorado. He received his bachelor’s and master’s degrees in geology at University of Texas at Austin. Steve started his career with Chevron in 1981 and worked in exploration and development assignments in the Rockies, mid-continent, Michigan Basin, and West Africa. Since leaving Chevron in 1990 he has worked on various projects in the U.S. and South America. Steve has worked the Piceance Basin and other Rocky Mountain basins at Barrett Resources, Williams, and Bill Barrett Corporation for the last ten years and has authored several publications, given numerous presentations, and led several fieldtrips. He is past president of the Grand Junction Geological Society and was presented the Rocky Mountain Association of Geologists’ Outstanding Scientist award in 2005. The publication entitled Understanding, Exploring, and Developing Tight-Gas Sands that he co-edited was awarded the Robert H. Dott Memorial Award for best AAPG special p u blication in 2008. Cumella is associate editor of the AAPG Bulletin and the Mountain Geologist.
technicaL Luncheons MARCH LUNCHEON
From outcrop analogue to flow simulation: Understanding the impact of geologic heterogeneity on hydrocarbon production
SPEAKER
Matthew D. Jackson Imperial College
Funded by the AAPG Foundation
11:30 am tuesday march 15, 2011 calgary teLus convention centre calgary, alberta
Please note: the cut-off date for ticket sales is 1:00 pm, thursday, march 10, 2011. csPg member ticket Price: $42.00 + gst. non- member ticket Price: $45.00 + gst.
Each CSPG Technical Luncheon is 1 APEGGA PDH credit.
Did you know that you can book a table for the Technical Luncheon? To book your company’s table or to buy tickets, visit http://www.cspg. org/events/events-luncheons.cfm.
Hydrocarbon reservoirs are geologically heterogeneous over a wide range of scale. This heterogeneity is a key control on fluid flow during hydrocarbon production, because geological (sedimentary, structural, and diagenetic) processes dictate the spatial distribution of petrophysical properties such as porosity, permeability, relative permeability, and capillary pressure. These properties control the flow of oil, water, and gas. Consequently, to understand, model, and predict fluid flow, it is essential to understand and model geological heterogeneity. This
is challenging for two reasons. The first is that geological heterogeneity is complex, ranging from the scale of individual pores to the scale of the entire reservoir (i.e., microns to kilometres). The second is that subsurface data is limited. Well data has high spatial resolution but is sparsely distributed; seismic data is extensive but has low spatial resolution. Poor understanding of geological heterogeneity leads to increased uncertainty in predictions of hydrocarbon recovery, and increases the risk associated with hydrocarbon extraction.
Recognizing that a reservoir model cannot represent explicitly every type and scale of heterogeneity raises a number of persistent questions. What are the key types and scales of heterogeneity that models should capture? Are these key heterogeneities the same for all reservoir and hydrocarbon types, and all recovery processes? What is the minimum level of model resolution / complexity required to make recovery predictions that are ‘good enough’? How should models best capture these key heterogeneities? To answer these questions requires the development of models based on rich datasets that capture heterogeneity at a high level of detail. Such models can be constructed using analogue outcrops. This presentation describes ongoing research to develop and apply outcrop analogue models, emphasizing the use of novel surfacebased modelling techniques in conjunction with adaptive gridding / meshing for flow simulation, and the insight gained into the impact of geologic heterogeneity on flow.
The approach is illustrated using examples of shallow-marine sandstone reservoir analogues from three contrasting depositional environments across a hierarchy of scales. The environments represented by the analogues comprise (1) a single, wavedominated shoreface-shelf parasequence; (2) two stacked, fluvial-dominated deltaic parasequence sets; and (3) multiple stacked, tide-dominated channel belts and tidal heteroliths. The datasets were obtained from well-exposed outcrops in Utah, USA; the Western Desert, Egypt; and the Isle of Wight, UK. They describe reservoir architecture in generic analogues for many shallow-marine reservoirs. The model results demonstrate that subtle aspects of reservoir architecture, which are typically neglected in subsurface models, can have a significant impact on flow and hydrocarbon recovery. Conversely, features which are routinely included because they are easy to model may be unimportant to flow. New
Webcasts sponsored by
reservoir modelling methods are required to capture subtle, yet important, geological heterogeneities. The methods developed here to handle outcrop datasets are equally applicable to subsurface reservoirs. They rely less on grid- or pixel-based methods, and integrate better with a new generation of reservoir simulators.
BIOGRAPHY
Matthew D. Jackson received his Bachelor’s degree in Physics from Imperial College London and his Ph.D. degree in Geological Fluid Mechanics from the University of Liverpool. He then rejoined Imperial College as a Research Associate in the Department of Earth Resource Engineering (now the Department of Earth Science and Engineering) working on a multidisciplinary project to characterize the impact of geologic heterogeneity on production from complex tidal reservoirs. He is currently Senior Lecturer in Geological Fluid Mechanics and Reservoir Engineering. He established (with Dr. Gary Hampson) the Outcrop Modelling Group at Imperial College, which he still co-leads. He also established and leads the Smart Wells Group. Jackson has received the Brian Mercer Award for Innovation from the Royal Society, the ‘Outstanding Associate Editor’ award of the Society of Petroleum Engineers Journal, and (as co-author) the SEPM ‘Excellence of Poster Presentation Award’ at the 2010 AAPG/SEPM Annual Meeting. He has served on the board of the Petroleum Group of the Geological Society of London, and currently serves on the board of the London Section of the SPE. He is a member of the AAPG, SPE, and AGU. He lives in London with his wife Liz and their son Nathaniel.
Jackson’s principal research interests are geologic reservoir modelling, numerical modelling of multiphase flow through porous media, understanding the interaction of geologic heterogeneity and flow, and downhole monitoring and control in instrumented and advanced wells. His research emphasizes an integrated approach to problem solving. He also has active and ongoing research into magma formation and transport in t he continental crust. He leads the Smart Wells Group and coleads the Outcrop Modelling Group at Imperial College London.
DIVISION TALKS STRUCTURAL DiviSion
Aspects of structural geology in northern Iraq: continental- to centimetre-scale
SPEAKER
Graham Banks , Ph.D. Western Zagros Resources
12 noon to 1pm
Thursday, February 3, 2011
Location: Please note: new venue Room B, +30 level, Husky Energy 707-8th Avenue SW
The Kurdistan region of northern Iraq has recently attracted attention from the oil and gas industry. Reserves estimates of 40 billion barrels of oil and 60 TCF of gas (US Geological Survey, 2010), relatively little exploration, favourable PSCs, and relative stability and security compared with the rest of Iraq mean the region has the potential to be a significant global energy player.
Wildcat wells have been drilled over the last
three years and significant results, new plays, and discoveries are now being announced monthly. More than 100 major anticlines remain undrilled and concepts like ‘fault-bound trap’ and ‘stratigraphic trap’ are yet to receive much consideration.
The region, dominated by the currently active Zagros and Taurus mountain belts and their inverting foreland basins, is a world-class structural laboratory. Yet few advances in mapping or understanding fold-thrust-fracture relationships have been published to date. Numerous Iraq structural geology tenets still need to be brought into the Plate Tectonics era.
Naturally, the first stage of mapping such an underexplored area is with remote imagery – for overview mapping of lithologies and structural fabrics, and for identifying areas for more focused exploration. ENVI software was used for advanced processing of Landsat and SPOT data. Results included:
• Distinguishing between lithological units that are difficult to discern on aerial photos.
• Identifying lineament trends and their ages relative to deformation episodes (of much influence on hydrocarbon recovery) on regional to sub-kilometre scales.
• Identifying relationships between lineament trends, shearing, fold geometry, and reactivation of deep faults.
The obvious structural trends are NW-SE (Zagros) and E-W (Taurus). However, the cover sequence of Iraq is also underlain by major transversal fault zones of Precambrian age that may have been repeatedly reactivated during the Phanerozoic. Topics that have been addressed include:
• Whether major transversal fault zones can be located using the geometry and spatial organisation of surface structures?
• What effects their repeated reactivation may have had on the Mesozoic and Cenozoic hydrocarbon-bearing section?
• What implications may there be for hydrocarbon exploration and prospectivity?
Fieldwork was recently undertaken to better understand the fault-fold-fracture-hydrocarbon relationships of northern Iraq, ground-truth remote imagery-based hypotheses, and chart structural domains. Structural geology results to date are insightful and often spectacular.
For additional information on CSPG Structural Division talks, please contact Darcie Greggs, Darcie.Greggs@huskyenergy.com.
DIVISION TALKS inTERnATionAL DiviSion
Offshore Benin, West Africa: An exploration case study of an underexplored basin
SPEAKER
Craig Boland B.Sc.(Hons.),M.Sc.,P.Geol.
President and Petroleum Exploration Consultant
Boland Exploration Consulting
12:00 Noon
Wednesday February 9th, 2010
Nexen Plus 15 Conference Centre Nexen Annex Building 7th Avenue and 7th Street SW Calgary, Alberta
The Atlantic margin of Western Africa consists of several sedimentary basins of Mesozoic to Tertiary age, their presence resulting from the fragmentation and rifting of Gondwanaland where South America and Africa separated. As with all such rift basins, the process consisted of an initial continental crust thinning, arching, and faulting around the Middle Jurassic. During the Lower Cretaceous, a series of grabens and half-grabens were filled with lacustrine and alluvial sediments of the Ise Formation. These were overlain in Albian through Turonian time with transgressive marine and marginal-marine sediments of the Abeokuta Formation.
The northern Gulf of Guinea creates the shoreline of Liberia, Ivory Coast, Ghana, Togo, Benin, Nigeria, and Cameroon and includes the Sierra Leone, Ivory Coast, Dahomey Embayment, Niger Delta, and Souala sedimentary basins. These marginal rift basins are defined to the north by the upper Guinea Arch, which extends for more than 2,000 km in an east-west orientation from Cameroon to Liberia. In the arch area, which contains the Birrimian Shield and the Dahomeyan Shield, metamorphic basement is exposed over large areas.
Benin’s exploration concessions are located within one of these sedimentary basins; namely, the Dahomey Embayment, which is an elongated basin that extends onshore from the Volta Delta (Ghana) in the west through Togo and Benin, and as far east as the Okitipupa High in Nigeria. Offshore, it extends further west along the continental shelf of Ghana. The basin’s t otal le ngth is approximately 700 km with a maximum width to the shelf break of nearly 180 km. The basin’s total area onshore and offshore to the 200 m isobath is approximately 50,000 sq. km. The offshore portion constitutes nearly 10,000 sq. km.
The known siliciclastic sediments of the Dahomey Embayment range from Neocomian (Early Cretaceous) to Recent. In general, the sedimentary section represents a gradation from terrestrial sediments near the base, through shallow marine, to deep marine (with restricted bottom circulation), and open marine. The overall section is capped with very young marine shelf sediments
Sponsored by
that prograde seaward. Such a sequence provides the necessary reservoirs and source rocks to complete any prospect inventory.
Within the exploration concessions, there are three major sandstone units that may form reservoirs. These three units have all been encountered within wellbores drilled at the Seme oil pool. They are the Ise Formation, the Albian / Aptian Sandstone, and the Turonian Sandstone; a fourth reservoir unit is interpreted from seismic and has been described as Maastrichtianaged turbidite channels, which fed the deeper-water, ponded turbidites.
Exploration for oil and gas in Benin began in 1964 with Union Oil (Unocal) shooting 2D seismic that resulted in the only oil discovery to date in Benin. The Seme
AFRICA
Call for Presenters
The January to June 2011 monthly meetings will focus on the E&D&P activities in the Africa Region. Dust off your corporate roadshow, past conference papers or field trip “Rock Shots” and entertain Calgary’s premier International G&G&E group for 30 to 40 minutes over lunch.
Contact either Trent Rehill (trehill@kulczykoil.com) or Bob Potter (rpotter@telusplant.net) for more information.
Shell arrived in 1971 and left in 1977 after acquiring only 2-D seismic with no drilling.
Recently, attention has once again been focused on Benin due to the increased activity and success in other nearby countries such as Cote d’Ivoire, Ghana, and western Nigeria. Profco drilled in September 1997, resulting in a dry hole at Ike #1.
Century International acquired shallowwater blocks in 1997 and, with KNOC, shot a large 3D program that was followed up with the drilling of one well in 2005. The Cotonou #1 was a dry well.
Deep water blocks were acquired by Kerr McGee and Kosmos in 2002 where a 3D program was completed and two additional wells were drilled. The locations, Fifa #1 and Hihon #1, were also dry holes.
Today, Century and hopes the remaining include
on-laps, resembling the North Sea Buzzard, and deeper-water, stacked turbidites.
BIOGRAPHY
Mr. Boland graduated from Memorial University of Newfoundland with his Bachelor of Science degree in Geology and his Master’s degree in Earth Science in 1984. During his 26-year career, he has held Senior and Executive positions with Major and Junior Exploration and Production Companies, both domestically and internationally. These companies include Texaco Canada, Imperial Oil and Gas, Intensity Resources, Archean Energy, Grizzly Resources, Ironhorse Oil and Gas, and Century International. Most recently, Mr. Boland was the Vice President of Exploration and founding partner for both Grizzly Resources and Ironhorse, along with being the Managing Director of Century International Oil and Gas. He has explored and operated in Western Canada, Offshore Eastern Canada, South America, West and
has been providing technical evaluations, opinions, financing, energy advice, and has been facilitator / broker for both startup and established energy firms worldwide. Mr. Boland is a member of APEGGA, AAPG, and CSPG.
There is no charge. Please bring your lunch. The facilities for the talk are provided courtesy of Nexen, coffee by IHS, and refreshments by Geochemtech Inc. For further information or if you would like to give a talk, please contact Bob Potter at (403) 863-9738 or ropotter@ telusplanet.net or Trent Rehill at (403) 6066717 or trehill@kulczykoil.ca. Or visit our new Facebook page (CSPG International Division).
Conventional Tools Don’t Work for Unconventional Reservoirs
IFP/Beicip’s Reservoir Simulation Technology
—For Shale Reservoirs
Innovative Software that is Comprehensive, Easy-to-use, Fully-Integrated, Flexible & Fast.
• Reduce costs of field development planning
• Optimize well spacing & hydraulic fracturing
• Identify sweet spots/SRV
• Find new ways to maximize EUR
• Greatly reduce history matching time
• Manage the uncertainty in your forecasts
• Utilize your time to analyze the reservoir/ wells instead of model building
diVision taLKs PALEONTOLOGY DIVISION
Digging in the dark: caves and Ice Age fossils in western North America
SPEAKER
Dr. Chris Jass
Royal Alberta Museum
7:30 PM
Friday, February 18th, 2011
Mount Royal University, Room B108 Calgary, Alberta
Caves of western North America contain important fossil deposits that provide insight into biological changes that occurred during the last Ice Age. Even in areas of the continent not commonly associated with karst topography, caves play a vital role in our understanding of Ice Age faunal change. Fossiliferous cave deposits often contain large numbers of specimens and sometimes preserve rare or uncommon specimens (e.g., soft tissue, dung). They also provide an important perspective on montane faunas, which are often otherwise unpreserved in the fossil record. Along with the many scientific benefits of working in caves come logistical challenges that are often not part of traditional paleontological fieldwork.
Resource Plays Spell Opportunity
► Identify Opportunities
► Generate Ideas
► Capture the Best Lands
► Overcome Technical Challenges
Resource Play Micro-Studies is an ongoing geoscience project that tracks the evolution of major resource plays across Western Canada. Keep your company up-to-date and technically informed.
Contact Cheryl Wright to subscribe today.
► One Play-by-Play Comparative Review
► Two Feature Play Micro-Studies
Dr. Chris Jass will take you on a tour of several Ice Age cave deposits in western North America, and will discuss research projects associated with sites in Arizona, Nevada, and Alberta. He will also discuss some of the unique challenges encountered while conducting fieldwork in caves, particularly since moving to Alberta. Come learn how caves contribute uniquely to our understanding of the Ice Age fossil record!
BIOGRAPHY
Chris Jass is the Curator of Quaternary Palaeontology at the Royal Alberta Museum, a position he has held since July 2008. He received his Master’s degree in Quaternary Studies from Northern Arizona University, and his Ph.D. in Geological Sciences from the University of Texas at Austin. His primary research interests are in mammalian biochronology, palaeoecology, and biogeography.
This event is jointly presented by the Alberta Palaeontological Society, Mount Royal University, and the CSPG Palaeontology Division. For details or to present a talk in the future, please contact CSPG Paleo Division Chair Philip Benham at 403-691-3343 or programs@albertapaleo.org. Visit the APS website for confirmation of event times and upcoming speakers: http://www.albertapaleo. org/.
Figure 1. Author at work.
diVision taLKs ENVIRONMENT DIVISION
Reclamation in oil sands mines
SPEAKER
Jon Hornung Suncor Energy
12:00 Noon
Friday, February 25, 2010
Centennial Place, East Tower
3rd Floor Conference Area 250 – 5th St SW Calgary, Alberta
While it can be argued that oil sands mining reclamation has been happening for over 25 years, there are still significant questions that have to be answered to attain a comprehensive understanding of the science. The practice of reclamation in the oil sands has evolved, and is considered an important planning step at Suncor, with large research and staff resources devoted to getting it right from start to finish. This life-cycle integration has helped make reclamation part of the larger mine plans
at Suncor. While we continue to integrate reclamation into many levels of mine planning, there are still questions that require answering; and Suncor is actively supports and encourages academics and other industry members to engage in the research that will provide those answers. There have been some significant successes recently that Suncor is proud to be a part of; namely, the reclamation of a tailings pond and the development of a tailings reduction operation. Regulators are working with industry and stakeholders to ensure top-notch science is being applied, and that industry is encouraged to apply new, innovative approaches. The presentation will conclude by speculating on the path forward for reclamation in oil sands.
BIOGRAPHY
Dr. Jon Hornung is a professional biologist who has been Environmental and Regulatory Team Lead and Senior Reclamation Advisor at Suncor Energy since 2007. He has worked for the University of Alberta, Alberta Sustainable Development, Alberta EcoTrust, the Alberta Conservation Association, the USGS, and the
Sponsored by
University of Costa Rica. Dr. Hornung has a Ph.D. in Resource Management and Aquatic Biology from the University of Alberta and a B.Sc. in Biology from the University of Ottawa.
INFORMATION
All lunch talks are free and o pen to t he public. Please bring your lunch. For information or to present a talk to the Environment Division please contact Andrew Fox at andrew.fox@ megenergy.com
REGISTER NOW
And join thousands of industry professionals at this year’s recovery 2011 convention in Calgary May 9 - 13, 2011 at the Calgary TELUS Convention Centre.
• Early bird deadline is March 31, 2011
• Registration includes: admission to the exhibition hall and Earth Science for Society exhibition, access to the technical program, poster sessions, Core Conference, Monday night mixer and Tuesday night reception at the Hyatt Regency Hotel
• Purchase tickets for the Monday night after party, Luncheon presentations, and Core Meltdown while registering to avoid disappointment. These events will sell out!
• Register online at www.geoconvention.com
Produced by:
UNICORNS IN THE GARDEN OF GOOD AND EVIL: Part 4 – Shale Gas
| By E. R. (Ross) Crain, P.Eng.
Unicorns are beautiful, mythical beasts, much sought after by us mere mortals. The same is true for petrophysical models for unconventional reservoirs. This is the fourth in a series of review articles outlining the simple beauty of some practical methods for log analysis of the unusual.
SHALE GAS BASICS
In petrophysical analysis, shale volume is one of the key answers used later to correct porosity and water saturation calculations for the effects of water bound to the clay minerals (clay-bound water = CBW). We define shale to be the sum of the clay mineral volume plus clay-bound water volume. Clays are complex minerals composed mostly of aluminum, silicon, and oxygen.
Strictly speaking, shale is a rock composed of very fine-grained material (Figure 1), composed mostly of clay minerals and possibly other minerals, such as calcite or quartz. Marlstone is used to describe limy or dolomitic shales. We will use the term “shale” to represent a rock component and “clay” to represent the minerals in the rock.
Gas shales are distinguished from shaly gas sands or silts by the fact that they contain adsorbed gas (just like coal beds), as well as free gas in porosity (unlike coal, which has virtually no macro-porosity). The adsorbed gas is roughly proportional to the organic content of the shale. Free gas is
proportional to the effective porosity and gas saturation in the pores.
Many rocks around the world are called shales, even though they are composed of minerals other than clays. Most of these socalled shales are really silts or silty shales or shaly silts. Many produce gas and some even produce oil, so we are now keen on analyzing shales more carefully than before (Figure 2).
Some shales, such as the Monterey Shale, Niobrara, and Milk River, are laminated shaly sands. These sands need to be analyzed with a Laminated Shaly Sand Model, not a Shale Gas Model. The sand laminations have good porosity and permeability. The shale laminations may contain low-level amounts of adsorbed gas, but this will be produced slowly through the sand fraction to the well bore.
A lot of shales are not shale at all, but are truly siltstones. The Montney shale in northeast British Columbia is roughly 45% quartz, 45% dolomite, and 10% other minerals (few of them are clay). The zone is radioactive due to uranium (but little kerogen), so it looks a lot like shale on quick-look log analysis; density-neutron separation and PE values are also close to shale values. This kind of reservoir needs to be treated as a tight-gas sand, as there is very little adsorbed gas.
Others are radioactive silty shales, such as
the Haynesville Shale, which is 50% clay and 50% quartz and calcite. This shale has low effective porosity and very poor permeability. Total organic carbon (TOC) is moderately high and there is adsorbed gas, so it gets treated as a true gas shale.
Using the wrong log analysis model will produce meaningless results, so be sure to understand what type of shale with which you are dealing.
Natural fractures in gas shales are an important component in assessing productivity. Fracture analysis using formation resistivity images (Figure 3, page 20) and acoustic televiewer images is covered on my website at www. spec2000.net
Figure 4 (page 20) is a series of core photos of a gas shale showing the typical laminated nature of shale. Gas is adsorbed in the microporosity on the clay surfaces. The natural fractures along the shale partings help move gas to the well bore when wellbore pressure is below formation pressure.
A log analysis model for shale gas is more complicated than for conventional reservoirs. The total organic content (kerogen) in the rock is the source of the gas and also takes up space. This space has to be segregated from the clay-bound water and conventional porosity. Figure 5 (page 22) illustrates these basic components. The
(Continued on page 20...)
Figure 1. Microphoto of a gas shale.
Figure 2. Schematic drawing of shale gas wells.
(...Continued from page 19)
conventional porosity can hold free gas and irreducible water. The clays hold the claybound water as well as adsorbed gas in the microporosity.
SORPTION ISOTHERMS – SHALE GAS
Sorption isotherms indicate the maximum volume of methane that a gas shale can store under equilibrium conditions at a given pressure and temperature. The direct method of determining sorption
isotherms involves cutting core that is immediately placed in canisters, followed by measurements of the volume of gas evolved from the shale over time. Lab units are usually g/cc but these are often reported as scf/ton of rock. When the sample no longer evolves gas, it is crushed and the residual gas is measured (Figure 6, page 22).
SHALE G AS -I N-PLACE – ADSORBED
Gas-in-place calculations in gas shales are done in two parts: adsorbed gas and free gas. Adsorbed gas-in-place is calculated from the isotherm curve, or from the actual gas content found in the lab, by using shale bed thickness and shale density as measured by well logs:
1: GIPadsorb = KG6 * Gc * DENS * THICK * AREA
Where:
GIPadsorb = gas in place (bcf)
Gc = sorbed gas from isotherm or coal analysis report (scf/ton)
DENS = layer density from log or lab measurement (g/cc)
THICK = layer thickness (feet)
AREA = spacing unit area (acres)
KG6 = 1.3597*10^-6
If AREA = 640 acres, then GIP = bcf/section (= bcf/sq.mile)
Multiply meters by 3.281 to obtain thickness in feet.
Multiply Gc in g/cc by 32.18 to get Gc in scf/ton. Typical shale densities are in the range of 2.20 to 2.60 g/cc.
Recoverable gas can be estimated by using the sorption curve at abandonment pressure (G a ) and replacing Gc in Equation 1 with (Gc - G a ).
SHALE G AS I N PLACE – FREE GAS
Free gas is determined by conventional log analysis using standard techniques. However, it is more difficult to quantify the parameters than for conventional reservoirs. Shale volume is the most important starting point, usually calibrated to data from x-Ray diffraction or thinsection point counts. The basic mineral mix is also developed from this data. Unless shale volume is reasonably calibrated, nothing else will work properly.
Effective porosity is best identified with a shale-corrected density-neutron complex lithology model. Here again, good control is necessary. Core analysis in low-porosity rocks needs some care and humidity control is important.
Water saturation is best obtained from the Simandoux equation. Dual-water models may also work, but may give meaningless results when shale volume is high. Special lab procedures to determine capillary pressure is needed to calibrate water saturation. Some shale gas reservoirs have moderate to high water saturations, others can have very low values.
Permeability is usually in the micro- to nano-Darcy region. Again special lab procedures are needed. Micro- and nanoCT scanning with post processing can generate all these values from core or sample chips.
Free gas in place is calculated from the usual volumetric equation:
2: B g = (Ps * (Tf + KT2)) / (Pf * (Ts + KT2)) * ZF
3: GIPfree = KV4 * PHI e * (1 - S w ) *THICK * AREA / B g
4: GIPtotal = GIPadsorb + GIPfree
Where:
AREA = reservoir area (acres)
B g = gas formation volume factor (fractional)
GIPfree = original free gas in place (bcf)
GIPtotal = total gas in place (bcf)
PHI e = effective porosity (fractional)
S w = water saturation in un-invaded zone (fractional)
THICK = layer thickness (feet)
Pf = formation pressure (psi)
Ps = surface pressure (psi)
Tf = formation temperature (°F)
Ts = surface temperature (°F)
ZF = gas compressibility factor (fractional)
KT2 = 460°F
KV4 = 0.043 560
on page 22...)
Figure 3. FMI image of fractures in a gas shale.
Figure 4. Core photo of gas shale - about 50% clay, 50% quartz plus calcite, 10 - 15% total porosity, 3 - 6% effective porosity, < 0.001 mD permeability. (Continued
Table 1. The best way to appreciate the unique properties of gas shale reservoirs is to look at the statistics, especially with respect to free and adsorbed gas, porosity, permeability, and costs.
ROCK SHOP
Fax4034515380 Cell4038192516
farhat@sableconsultants.com SABLECONSULTANTS.COM
data was available so free gas saturation is not calibrated.
(...Continued from page 20)
If AREA = 640 acres, then GIP = bcf/section (= bcf/sq mile).
Multiply meters by 3.281 to obtain thickness in feet.
SHALE GAS EXAMPLE
(See Figure 7.)
ABOUT THE AUTHOR
E. R. (Ross) Crain, P.Eng. is a Consulting Petrophysicist and a Professional Engineer with over 45 years of experience in reservoir description, petrophysical analysis, and management. He has been a specialist in the
integration of well log analysis and petrophysics with geophysical, geological, engineering, and simulation phases of oil and gas exploration and exploitation, with widespread Canadian and Overseas experience.
His textbook, Crain’s Petrophysical Handbook on CD-ROM, is widely used as a reference to practical log analysis. Mr. Crain is an Honourary Member and Past President of the Canadian Well Logging Society (CWLS), a Member of Society of Petrophysicists and Well Log Analysts (SPWLA), and a Registered Professional Engineer with Alberta Professional Engineers, Geologists and Geophysicists (APEGGA ).
Figure 5. Petrophysical model for a gas shale.
Figure 6. Sorption isotherm for a gas shale.
Figure 7. Log analysis in a silty gas shale. XRD shows Vsh = 0.40 to 0.45, so parameters were chosen to achieve this. Core porosity is available and shale properties were adjusted to achieve a good porosity match to core. TOC is not large so adsorbed gas will be relatively small. No capillary pressure
Sh ALE GAS Part 6 - Influence of Technology on Shale Gas Development
| By C. R. Clarkson1, R. Aguilera2, P. K. Pedersen1, R. J. Spencer1,3
1Department
of
Geoscience, University of Calgary, 2Schulich School of Engineering, University of Calgary, 3Alberta Innovates Technology Futures
INTRODUCTION
In Part 2 of this Shale Gas Series, we described the history of shale gas development in North America, and referred to the impact that technology has had on shale gas development. In this article, we further discuss the impact of key technologies that have enabled commercial development of shale gas reservoirs. Successful development of the Barnett Shale over the past decade with these technologies has set the stage for commercial development in other shale plays in North America. The technologies that are commonly agreed to be responsible for success in the Barnett Shale are:
1. Hydraulic fracture stimulation, using slickwater fracturing (SWF), including refracturing of wells previously frac’d with other fluid types (e.g., gel).
2. Multi-fractured horizontal wells (MFHW).
3. Simultaneous or sequential fracturing of adjacent horizontal wells.
4. Surveillance technologies, including microseismic.
Application of technologies 1 – 3 is generally believed to cause a large reservoir surface area to be contacted through the generation of a complex fracture network, including reactivation of existing natural fractures in some cases. Technology 4 has allowed us to infer the geometry of the induced hydraulic fracture network, lending itself to improved completion / hydraulic fracture design. We will discuss, in turn, how each of these technologies has led to improved well performance in the Barnett.
The success of these technologies has led to their trial in other shale plays in North America, and with adaptation and variation, additional successes. However, as we have discussed in previous articles, what we call “shale” plays today exhibit a wide variation in geologic environment, reservoir, rock, and native fluid properties. In some cases, application of the stimulation technologies mentioned may not be optimal. We will, therefore, discuss additional considerations for shale gas development.
2007).
Lastly, improved development of existing and new shale gas plays will require refinement of existing technology and application of new technology. We finish the article by speculating which technologies may prove important for future growth of shale gas development.
Much of the information used in this article was obtained from recent summary articles by King (2010), Cramer (2008), Britt and Smith (2009), Mayerhofer (2008), and Warpinski (2009). The reader is referred to those excellent works for further details.
SLICKWATER FRACTURING
In a recent address to the AAPG/SEG/SPE/ SPWLA Hedberg Research Conference entitled “Critical Assessment of Shale Resource Plays” (Austin, Texas; Dec. 5-10, 2010), Dan Steward, formerly a Vice President of Geology with Mitchell Energy (later acquired by Devon Energy), discussed the importance of slickwater fracturing (SWF) to Mitchell’s initial success in the Barnett. Prior to the application of this technology, Mitchell Energy had primarily been using more expensive gel or foam fracs until the late 1990s, when Nick Steinsberger, formerly a Staff Engineer with Mitchell / Devon Energy, decided to try less-expensive slickwater treatments. Slickwater is a water-based fluid with very few additives and, hence, has a very low viscosity. When combined with proppant, such as sand, slickwater fracturing provides
a low-cost alternative to more exotic fluid types.
Although slickwater fracs were first tried in the Barnett because of their relatively low cost, this stimulation treatment style quickly was demonstrated to outperform gel-based hydraulic-fracture treatments (Figure 1). According to King (2010), the success of slickwater fracturing is due to a combination of factors:
• enlarging channels of flow in microfractures and laminations due to leakoff of the low-viscosity slickwater,
• an enhanced contacted surface area with the low-permeability matrix (containing water to fractures), and
• apparent lack of formation damage due to contact with water.
The creation of a complex fracture network, with high-contacted surface area, is now believed to be the primary cause for success of SWF in the Barnett, although evidence for the creation of such a network did not become available until microseismic monitoring of treatment wells was attempted (Fisher et al., 2002). Although the low-viscosity of slickwater appears to be a key ingredient in the creation of fracture complexity through activation, dilation, and shear of natural fractures (Warpinski, 2009), other factors, which may not be present in all shale plays, appear important, including: extremely low
(Continued on page 24...)
Figure 1. Production data of a Barnett Shale well before and after re-fracturing operations (Bowker,
to lack of one or more of the favorable conditions discussed above.
MULTI-FRACTURED HORIZONTAL WELLS
completions allow for better control of fracture initiation (at perforation clusters), whereas it is more difficult to control the number and location of fracture initiation points in an openhole completion.
(...Continued from page 23)
matrix permeability; low in-situ horizontal stress and stress anisotropy; favorable rock mechanical properties (brittleness), as quantified by a low Poisson’s ratio and High Young’s Modulus; and rock fabric. Fracturing operations also come into play, including pump-rates, fluid volumes, and sand tonnages (King, 2010). Fracture complexity will be discussed in further detail below.
SWF clearly has been a key ingredient for commercializing the Barnett shale, but this technology may not work in all shale plays, particularly where the shales are very sensitive to water, or where fracture complexity creation is not possible due to lack of one or more of the favorable conditions discussed above.
MULTI-FRACTURED HORIZONTAL WELLS
To maximize the amount of reservoir contacted by a single wellbore, horizontal wells oriented in a direction to promote transverse fracturing have emerged as a key technology (Figure 3a). The objective of multi-stage fracturing in these horizontal wells is to create as much fracture complexity (or “stimulated reservoir volume”) as possible that is in hydraulic communication with the wellbore. The current trend is for long horizontal wells stimulated in many stages. Both casedhole and openhole designs (Figure 3b) have been used, as well as various kinds of stage isolation. An excellent discussion of completion designs used in the Montney tight gas / shale play in We stern Canada was provided by Thompson et al. (2009).
To maximize the amount of reservoir contacted by a single wellbore, horizontal wells oriented in a direction to promote transverse fracturing have emerged as a key technology (Figure 3a). The objective of multi-stage fracturing in these horizontal wells is to create as much fracture complexity (or “stimulated reservoir volume”) as possible that is in hydraulic communication with the wellbore. The current trend is for long horizontal wells stimulated in many stages. Both casedhole and openhole designs (Figure 3b) have been used, as well as various kinds of stage isolation. An excellent discussion of completion designs used in the Montney tight gas / shale play in Western Canada was provided by Thompson et al. (2009).
SWF clearly has been a key ingredient for commercializing the Barnett shale, but this technology may not work in all shale plays, particularly where the shales are very sensitive to water, or where fracture complexity creation is not possible due to lack of one or more of the favorable conditions discussed above.
MULTI-FRACTURED HORIZONTAL WELLS
King (2010) notes that another potential reason for the success of refracs of wells previously stimulated with gelled fluids is by-pass of gel damage. Further, fracture re-orientation during re-fracturing operations appears to contact new reservoir (Bowker, 2007; Figure 2), causing an increase in production rate, and possibly reserves additions.
a) b)
SWF clearly has been a key ingredient for commercializing the Barnett shale, but this technology may not work in all shale plays, particularly where the shales are very sensitive to water, or where fracture complexity creation is not possible due
Cased and cemented completions are the most common in the Barnett, where multiple perforation intervals (perforation “clusters”) are used to initiate fractures for the purpose of creating fracture complexity. For this completion style to be effective for stage isolation, a good cement job is critical (King, 2010). It is generally believed that more perforation clusters and stages in cased and cemented completions increase the probability of dense fracturing. For openhole systems (Figure 3b), packers are typically used to isolate stages and shiftable valves are used to convey the hydraulic fracture treatment to the formation – balls of decreasing diameter per stage are used to open frac ports for each successive stage. It is generally believed that cemented
Mayerhofer et al. (2008) discussed the importance of horizontal lateral orientation relative to fracture network azimuth (Figure 4a) and well placement and spacing (Figure 4b) on stimulated reservoir volume (SRV) coverage. For the NE-SW-oriented laterals in Figure 4a, if the fracture direction is in the same orientation as the lateral (lefthand side of Figure 4a), then a smaller SRV results, whereas transverse fracture orientation tends to result in greater SRV coverage (righthand side of Figure 4a). Mayerhofer et al. (2008) also suggest that if SRVs created by individual wells are relatively small, then closer well spacings (see Figure 4b) may be required to create overlap between SRVs and improve recovery. Some operators promote tighter frac spacing to create greater SRV coverage for each well so that well spacing does not have to be as close (Ray Ambrose, personal communication) – it is obviously less costly to pump more frac stages than to drill and complete new wells. Clearly this is an important design consideration for shale gas development.
Some operators have chosen to use simultaneous or sequential fracturing to improve SRV coverage, as discussed in the next section.
To maximize the amount of reservoir contacted by a single wellbore, horizontal wells oriented in a direction to promote transverse fracturing have emerged as a key technology (Figure 3a). The objective of multi-stage fracturing in these horizontal wells is to create as much fracture complexity (or “stimulated reservoir volume”) as possible that is in hydraulic communication with the wellbore. The current trend is for long horizontal wells stimulated in many stages. Both casedhole and openhole designs (Figure 3b) have been used, as well as various kinds of stage isolation. An excellent discussion of completion designs used in the Montney tight gas / shale play in Western Canada was provided by Thompson et al. (2009).
SIMULTANEOUS OR SEQUENTIAL FRACTURING OF ADJACENT HORIZONTAL WELLS
“Simul-fracs” and “zipper-fracs” have also been trialed in the Barnett. Simul-fracs
Figure 2. Cartoon depicting the geometry of Barnett re-fracs (Bowker, 2007).
Figure 2. Cartoon depicting the geometry of Barnett re-fracs (Bowker, 2007).
b)
Figure 2. Cartoon depicting the geometry of Barnett re-fracs (Bowker, 2007).
Figure 3. (a) Illustration of a multi-fractured horizontal well and (b) a method of frac stage isolation in an openhole completion. Source: Bob Barree short course notes, 2009.
Higher Recovery with More SRV Overlap?
Figure 4. (a) Illustration of the importance of lateral orientation and (b) well placement and spacing on stimulated reservoir volume (“SRV”) coverage. Modified from Mayerhofer et al. (2008).
SIMULTANEOUS OR SEQUENTIAL FRACTURING OF ADJACENT HORIZONTAL WELLS
“Simul-fracs” and “zipper-fracs” have also been trialed in the Barnett. Simul-fracs involve the fracturing of multiple (two or more) parallel laterals simultaneously in an attempt to create greater hydraulic fracture network coverage. The physical reasoning for why this works is that stresses created through the fracturing of one stage are used to divert the direction of fracture propagation from an offsetting stage for the purpose of contacting new rock. Zipper-fracs are a variation on this, where frac stages in offset wells are executed in short alternating sequence. As one can imagine, these operations require tremendous co-ordination between frac crews and equipment, and large or even multiple pads (King, 2010). Although the merits of these operations remain debatable, there have been positive indications from those operators that have tried it.
involve the fracturing of multiple (two or more) parallel laterals simultaneously in an attempt to create greater hydraulic fracture network coverage. The physical reasoning for why this works is that stresses created through the fracturing of one stage are used to divert the direction of fracture propagation from an offsetting stage for the purpose of contacting new rock. Zipperfracs are a variation on this, where frac stages in offset wells are executed in short alternating sequence. As one can imagine, these operations require tremendous co-ordination between frac crews and equipment, and large or even multiple pads (King, 2010). Although the merits of these operations remain debatable, there have been positive indications from those operators that have tried it.
SURVEILLANCE TECHNOLOGIES, INCLUDING MICROSEISMIC
Although the advantage of slickwater fracturing over other fracturing treatments in the Barnett was clear by the end of the 1990s, the reason for its success remained
unclear until microseismic observation of fracture treatments were implemented. In the landmark work of Fisher et al. (2002), it was demonstrated that hydraulic fractures in the Barnett Shale form a complex network (Figure 5), as opposed to a bi-wing geometry that had been classically modeled in conventional reservoirs. According to Warpinski et al. (2008), multiple-stage light sand fracture treatments “often overlap and interact – frequently by design –and develop quite complicated fracture networks.” They also note that a full network spectrum of fracture geometries, as illustrated in Figure 5a (page 26), is possible for shale gas plays. Evidence for fracture complexity in the Barnett Shale, as inferred from microseismic data, is given in Figure 5b (page 26).
to provide geometric and behavioral information about the process.” Monitoring hydraulic fracture stimulations in vertical wells (Figure 6, page 26) requires placement of an array of three-component geophones in an offset vertical well, at a depth close to the zone being stimulated in the treatment well. Seismic energy associated with microseisms created by hydraulic fracture operations is processed, resulting in placement of the “events” in space (Warpinski, 2009).
SURVEILLANCE TECHNOLOGIES, INCLUDING MICROSEISMIC
Mayerhofer et al. (2008) demonstrated that well performance was directly tied to the estimates of SRV from microseismic data (Figure 7, page 27).
Although the advantage of slickwater fracturing over other fracturing treatments in the Barnett was clear by the end of the 1990s, the reason for its success remained unclear until microseismic observation of fracture treatments were implemented. In the landmark work of Fisher et al. (2002), it was demonstrated that hydraulic fractures in the Barnett Shale form a complex network (Figure 5), as opposed to a bi-wing geometry that had been classically modeled in conventional reservoirs. According to Warpinski et al. (2008), multiple-stage light sand fracture treatments “often overlap and interact – frequently by design – and develop quite complicated fracture networks.” They also note that a full network spectrum of fracture geometries, as illustrated in Figure 5a, is possible for shale gas plays. Evidence for fracture complexity in the Barnett Shale, as inferred from microseismic data, is given in Figure 5b.
According to Warpinski (2009), “M icroseismic monitoring is the placement of receiver systems in advantageous positions from which small earthquakes (microseisms) induced by some downhole process can be detected and located
Although microseismic data has become the primary surveillance technology for interpreting hydraulic fracture geometries in shale gas reservoirs, it should be noted that other surveillance methods may be used to infer fracture geometry and contacted surface area. For example,
(Continued on page
Adjacent
Figure 4. (a) Illustration of the importance of lateral orientation and (b) well placement and spacing on stimulated reservoir volume (“SRV”) coverage. Modified from Mayerhofer et al. (2008).
spectrum
possible
that may be encountered in shale and (b)
for complex fracture geometry
Warpinski et al. (2008). Cipolla et al. (2008) used a fracture complexity index, which is the ratio of fracture width to length as determined from the microseismic cloud, to establish the degree of frac complexity – complex fracture fracture networks have nearly equal width and length.
(...Continued from page 25)
daily (or more frequent) monitoring of production rates and flowing pressures may be used for rate-transient analysis, which may, in turn, be interpreted to derive a total hydraulic fracture halflength, or contacted matrix surface area if linear flow is exhibited – this is the subject of Part 7 of our series. The estimated half-length or contacted surface area may then be used to infer fracture complexity (large contacted surface areas imply fracture complexity). Tracer flowback and production logs can also be used to confirm geometries interpreted from production analysis and microseismic data (King, 2010). In Part 8 of our series, we will discuss the incorporation of these surveillance methods into a workflow for optimizing shale gas development.
ADDITIONAL CONSIDERATIONS FOR SHALE GAS COMPLETIONS / STIMULATION
Although the combination of SWF and MFHW has worked well in the Barnett Shale, we emphasize that one size does not fit all for shale plays. Depending on the properties of the shale play in question, fluid, proppant, stimulation treatment parameters (rate and pressure), and even well geometry may need to be altered. For example, in some instances higher conductivity hydraulic fractures may be required (e.g., for ductile shales) – slickwater has a relatively low sandcarrying capacity than other fluid types and is not the optimal choice for achieving
conductivity. If fracture complexity cannot be achieved in the play of interest, due to the combination of rock / reservoir properties and in-situ stress, then highrate / large-volume slickwater fracs may not be desirable. Water and horsepower availability may also not be favorable for some plays, particularly those located in remote areas. Further, water-sensitive shales may require fluids that are less reactive, such as gelled hydrocarbon (propane or butane) gas fracs (King, 2010).
Type (and amount) of proppant and loading may also be play-dependent. Sand (usually 100 mesh), which is not believed to provide high fracture conductivity, is commonly used for shale gas plays; larger proppant sizes may be required to achieve this. Proppant loading (sand concentration) is play-dependent, and some shale plays with high in-situ stress may require highercrush-strength, man-made proppants as opposed to sand. There are many more nuances that go into fracture treatment
Figure 5. (a) Illustration of
of
fracture geometries
evidence
in Barnett Shale. Modified from
Figure 6. Cartoon illustrating microseismic monitoring of a hydraulic fracture stimulation of a vertical well. Image courtesy of John Logel.
Estimate SRV size by “binning” microseismic data
Relate SRV to cumulative production
Figure 7. Illustration of a method for relating SRV size (only plan view shown above), as established from microseismic data, to well production. Modified from Mayerhofer et al. (2008).
design that cannot be covered here – the reader is referred to King (2010) for additional details.
Lastly, wellbore architecture / completion style is similarly play-dependent. For example, in some shale plays where there are multiple target intervals spread over a large vertical section, then multi-stage vertical wells may be more cost effective. The lesson: geology matters!
NEEDED IMPROVEMENTS IN TECHNOLOGY
exhaustive list of these technologies and their application below:
• Integration and refinement of techniques for selection of target intervals, vertically within the shale section, and laterally within the horizontal. Continued improvement of petrophysical, core, and cuttings analysis; diagnostic fracture injection (DFIT); and mini-frac tests to quantify key reservoir and rock properties such as porosity, permeability, and brittleness or rock strength will be required.
isotopic signature surveys (Strapoc et al., 2010), and microseismic to evaluate stimulation effectiveness in various portions of the well.
Although microseismic data has become the primary surveillance technology for interpreting hydraulic fracture geometries in shale gas reservoirs, it should be noted that other surveillance methods may be used to infer fracture geometry and contacted surface area. For example, daily (or more frequent) monitoring of production rates and flowing pressures may be used for rate-transient analysis, which may, in turn, be interpreted to derive a total hydraulic fracture half-length, or contacted matrix surface area if linear flow is exhibited – this is the subject of Part 7 of our series. The estimated half-length or contacted surface area may then be used to infer fracture complexity (large contacted surface areas imply fracture complexity). Tracer flowback and production logs can also be used to confirm geometries interpreted from production analysis and microseismic data (King, 2010). In Part 8 of our series, we will discuss the incorporation of these surveillance methods into a workflow for optimizing shale gas development.
In order to improve shale gas development efficiency and economics, there are several technological refinements and developments that we feel will be necessary in the future. We provide a non-
ADDITIONAL CONSIDERATIONS FOR SHALE GAS COMPLETIONS / STIMULATION
ROCK SHOP
• Improved integration of surveillance techniques such as tracers, production logs (Clarkson and Beierle, 2010), distributed temperature surveys (Huckabee, 2009), gas composition, and
• Improved methods for quantifying the impact of hydraulic fracture treatment and reservoir properties on well performance. There has been a rapid evolution in rate-transient methods (subject of Part 7 of this series), but quantitative methods for evaluating complex, multi-fractured horizontal wells are still in their infancy, particularly when the completion is heterogeneous (variable frac height and length along the we ll). Flowback analysis will also become more important in the future.
(Continued on page 28...)
Although the combination of SWF and MFHW has worked well in the Barnett Shale, we emphasize that one size does not fit all for shale plays. Depending on the properties of the shale play in question, fluid, proppant, stimulation treatment parameters (rate and pressure), and even well geometry may need to be altered. For example, in some instances higher conductivity hydraulic fractures may be required (e.g., for ductile shales)
Figure 7. Illustration of a method for relating SRV size (only plan view shown above), as established from microseismic data, to well production. Modified from Mayerhofer et al. (2008).
• Continued development of “hybrid” frac techniques where slickwater is used to open fissures and natural fractures, and higher-viscosity fluids are used to increase fracture conductivity (King, 2010).
• Continued development of methods to create fracture complexity (where possible) – longer lateral lengths, more frac stages, continued trial of simuland sequential-fracturing techniques.
• Improved methods for shale play and prospect analysis (play and prospect screening).
• Continued development of coupled geomechanical / flow simulation and coupled DFN / flow simulation (Rogers et al., 2010) to model fracture complexity and long-term production characteristics.
• Development of frac simulators that model fracture complexity for use in hydraulic fracture design for shale gas.
• Use of nanotechnology to assist with post-frac analysis – for example, the development of “smart proppants” that identify where the proppant has gone at large distances from the wellbore.
• Improved geochemical prospecting (Jarvie et al., 2010 and Tang et al.,
2010) for shale plays that exhibit a wide range of organic matter thermal maturity and fluid types (dry gas, wet gas, retrograde condensate, and oil).
• Improved methods for water reusage and recycling for large-volume slickwater fracturing operations.
Although not a technical issue, there is also a need to improve stakeholder relations. Shale gas operators will increasingly be required to engage and educate stakeholders regarding the nature of shale gas operations and associated environmental risks. Lack of stakeholder buy-in to their operations is perhaps the greatest risk to future shale gas development.
REFERENCES
Barree, R. D. 2009. Hydraulic fracturing, theory and practice. Short course notes. Barree and Associates, 2009.
B owker, K. A. 2007. Development of the Barnett Shale Play, Fort Worth Basin. Search and Discovery Article #1026, posted April 18, 2007.
Britt, L. K., and Smith, M. B. 2009. Horizontal well completion, stimulation optimization, and risk mitigation. Society of Petroleum
Engineers Paper 125526 presented at the 2009 SPE Eastern Regional Meeting, Charleston, WVA, 23-25 September.
Cipolla, C. L., Warpinski, N. R., Mayerhofer, M. J., Lolon, E. P., and Vincent, M. C. 2008. The relationship between fracture complexity, reservoir treatment and fracture treatment design. Society of Petroleum Engineers Paper 115769 presented at the 2008 SPE Annual Technical Conference and Exhibition, Denver, CO, 21-24 September.
Clarkson, C. R., and Beierle, J. J. 2010. Integration of microseismic and other postfracture surveillance with production analysis: A tight gas study. Society of Petroleum Engineers Paper 131786 presented at the SPE Unconventional Gas Conference held in Pittsburgh, Pennsylvania, 23-25 February.
Cramer, D. D. 2008. Stimulating unconventional reservoirs: Lessons learned, successful practices, areas for improvement. Society of Petroleum Engineers Paper 114172 presented at the 2008 SPE Unconventional Reservoirs Conference, Keystone, CO, 10-12 February.
Fisher, M. K., Wright, C. A., Davidson, B. M., Goodwin, A. K., Fielder, E. O., Buckler, W.
S., and Steinsberger, N. P. 2002. Integrating fracture mapping technologies for optimizing in the Barnett Shale. Society of Petroleum Engineers Paper 77441 presented at the 2002 SPE Annual Technical Conference and Exhibition, San Antonio, TX, 29 September - 2 October.
Huckabee, P. 2009. Optic fiber distributed temperature for fracture stimulation diagnostics and well performance evaluation. Society of Petroleum Engineers Paper 118831 presented at the 2009 SPE Hydraulic Fracturing Technology, The Woodlands, TX, 19-21 January.
Jarvie, D., Jarvie, B., Courson, D., Garza, T., Jarvie, J., and Rocher, D. 2010. Geochemical tools for assessment of tight oil reservoirs. Poster presentation at the AAPG/SEG/SPE/ SPWLA Hedberg Research Conference: Critical Assessment of Shale Resource Plays, Austin, TX, 5-10 December, 2010.
King, G. E. 2010. Thirty years of gas shale fracturing: What have we learned? Society of Petroleum Engineers Paper 133456 presented at the SPE Annual Technical Conference and Exhibition, Florence, Italy, 19-22 September.
Mayerhofer, M. J., Lolon, E. J., Warpinski, N.
R., Cipolla, C. L., Walser D., Rightmire, C. M., and Garb, F. A. 2008. What is stimulated reservoir volume? Society of Petroleum Engineers Paper 119890 presented at the SPE Shale Gas Production Conference, Fort Worth, TX, 16-18 November.
Rogers, S., Elmo, D., Dunphy, R., and Bearinger, D. 2010. Understanding hydraulic fracture geometry and interactions in the Horn River Basin through DFN and numerical modeling. Society of Petroleum Engineers Paper 137488 presented at the CSUG/SPE Canadian Unconventional Resources and International Petroleum Conference held in Calgary, Alberta, 19-21 October.
Strapoc, D., Michael, G. E., Roper, J., and Maguire, M. 2010. Insights into shale gas production and storage from gas chemistry – What is it telling us? Poster presentation at the AAPG/SEG/SPE/SPWLA Hedberg Research Conference: Critical Assessment of Shale Resource Plays, Austin, TX, 5-10 December, 2010.
Tang, Y., Xia, X., Ferworn, K., and Zumberge, J. 2010. Kinetics and mechanism of s hale ga s formation: A quantitative interpretation of gas isotope “Rollover”? Oral presentation at the AAPG/SEG/SPE/SPWLA Hedberg
Research Conference: Critical Assessment of Shale Resource Plays, Austin, TX, 5-10 December, 2010.
Thompson, D., Rispler, K., Stadnyk, S., Hoch, O., and McDaniel, B. W. 2009. Operators evaluate various stimulation methods for multizone stimulation of horizontals in northeastern British Columbia. Society of Petroleum Engineers Paper 119620 presented at the 2009 SPE Hydraulic Fracturing Technology, The Woodlands, TX, 19-21 January.
Warpinski, N. R. 2009. Microseismic monitoring: Inside and out. Society of Petroleum Engineers Distinguished Author Series, JPT, November 2009.
Warpinski, N. R., Mayerhofer, M. J., Vincent, M. C., Cipolla, C. L., and Lolon, E. P. 2008. Stimulating unconventional reservoirs: Maximizing network growth while optimizing fracture conductivity? Society of Petroleum Engineers Paper 114173 presented at the 2008 SPE Unconventional Reservoirs Conference, Keystone, CO, 10-12 February.
GO TAKE A HIKE
Riding the Foothills Erratics Train, Calgary and Okotoks, AB
| By Philip Benham, Jim Dolph and Yingchun Guan
Dedicated in memory of Eric Mountjoy and Archie Stalker who are so closely linked to our understanding and interpretation of the erratic train. The Reservoir Committee welcomes contributions from our readership to this series. If you wish to offer a submission to Go Take a Hike on your favourite hike of geological interest, e-mail the Reservoir at caitlin.young@cspg.org for more information.
Locations:
● Split Rock & Paskapoo QuarryWest Nose Creek Confluence Park –drive 200m north from Beddington Trail on Harvest Hills Blvd, turn right in public parking area and follow walking trail 500m East. Quarry below rock.
● Nose Hill erratic – Proceed 200m south from parking area at Berkley Gate and then west along Porcupine Valley another 200m.
● Sienna Hills erratic – playground, junction Sienna Hills Dr. and Crescent.
● Lakeview Baptist Church erratic – Lakeview Drive.
● Big Rock , ~6 km west of Okotoks on Hwy 7. Walk 150m north of parking lot.
Route: All of these rocks can be visited in a day and are either near the roadside or less than 500m from parking areas. Big Rock and Split Rock have gravel trails and mild inclines. Start point is at your discretion.
A 600 km-long line of boulders extends from Jasper through southern Alberta. It represents the meeting point between the Cordilleran and Laurentide Ice Sheets at the termination of the last Ice Age. The boulders are primarily a grey to pink-coloured, coarse-grained to pebbly quartzite that often shows cross-bedding characteristic of a braided stream setting. Dr A.M. Stalker suggested in the 1950s that the singular composition of the boulders was indicative of a rockslide onto the glacial ice. These boulders were
then carried east by Cordilleran ice until they contacted the Laurentide Ice sheet and were distributed far southwards as part of a medial moraine.
Roed et al. (1967) identified the slide area as Mount Edith Cavell in Jasper N.P., where Cambrian quartzite is extensively exposed along a major glacier outflow route. Dating of the Foothills erratics train is tricky, but is speculated to be 1720,000 years old and took perhaps 600 years for the boulders to move to their current position. Big Rock is the world’s largest glacial erratic. It is 41m long and weighs in at over 16,000 tons.
Nose Hill erratic (not illustrated) has a depression around it where herds of buffalo once used it to rub their itching hides. Other Ice age features observed in exposed gravel at Nose hill include frost shattered pebbles and “fossil” ice wedges from a time when temperatures were 9-14ºC cooler than today (Morgan, 1969). Nose Hill Creek and Fish Creek are misfit streams; mere shadows of the engorged rivers of glacial melt-waters that incised large valleys in short periods of time.
References:
Morgan, A.V., 1969. Journal of Geology, v. 77, no. 3, p. 358-364.
Roed, M. A., Mountjoy, E. W., and Rutter, N. W. 1967. C.J.E.S. v. 14, p. 624-632.
Stalker, A. M. 1956. GSC Bull. 37, 28 p.
by
Background
Photo
Astrid Arts.
Left: Split Rock. Its pebbly sandstone beds rest upright. Check for cross-beds. Right: Paskapoo Fm quarry. Sandstone was extracted from four sites along Nose Hill Creek for building stone between 1900 and 1915 using dynamite, sledge hammers, and hardwood mallets.
Big Rock, “discovered” by James Hector in 1863, is a collection of boulders that come from a very large erratic that split up during transport, probably near the end of its journey.
Fresh surfaces on Big Rock expose the coarse-grained nature of the sandstone, as well as cross-beds.
an important trail marker for early first Nations
offerings or
Quartzite erratic, Lakeview Baptist Church
Sienna Hills erratic.
The southern face of Big Rock contains red ochre markings (see arrow). The Foothills erratics train was
travelers. This particular erratic was revered and features in several legends. The Blackfeet viewed it as a medicine rock and often left
said prayers at this site.
2010 csPG awards
Technical awards
Stanley Slipper Gold Medal for Outstanding Career Contributions to Oil and Gas Exploration in Canada
Dr. Norman Fischbuch
R.J.W. Douglas Medal for Outstanding Contributions to the Understanding of Sedimentary Geology in Canada
Dr. Deborah Spratt
Honourary Membership for Distinguished Service to the Society
Dr. Michael Cecile
Dr. George Pemberton
Link Award for Best Presentation –Technical Luncheon Series
Dr. Jen Russel-Houston
“How an Underground Approach to Commercial Bitumen Development of the Grosmont Formation Could Maximize Profitability and Minimize Environmental Footprint”. Presented at the March 23, 2010 CSPG Technical Luncheon.
Medal of Merit for Best Paper Related to Canadian Petroleum Geology
Dr. Jack Wendte, David Sargent, Alan Byrnes, and Dr. Ihsan Al-Aasm.
“Depositional facies framework, evolution, and reservoir architecture of the Upper Devonian Jean Marie Member (Redknife Formation) in
the July Lake area of northeastern British Columbia.” Bulletin of Canadian Petroleum Geology, v. 57 (3), p. 209-250.
and Honourable Mention to:
Dr. Derald Smith, Dr. Stephen Hubbard, Dr. Dale Leckie, and Dr. Milovan Fustic.
“Counter point bar deposits: lithofacies and reservoir significance in the meandering modern Peace River and ancient McMurray Formation, Alberta, Canada.” Sedimentology, v. 56, p. 1655-1669.
Volun T eer awards
President’s Award for Outstanding Service by a CSPG Member
Dr. Mark Cooper
Colin Yeo
Tracks Awards for Members Who Have Set New Standards of Excellence
Denise Hodder
Vic Panei
Partnership Tracks Award for NonCSPG members or Non-Geologists who Have Made Outstanding Contributions to CSPG
John Cuthbertson
Annette Milbradt
Service Awards for Members who Have Served the Society for Over Five Years
Jennifer Adams
Astrid Arts
Peter Aukes
Wes Bader
Andreas Bayer
Philip Benham
George Bowley
Peter Boyle
Nathan Bruder
David Caldwell
Dr. Mark Caplan
Allan Carswell
Richard Chisholm
Nancy Chow
Andre Chow
Penny Christensen
John Cody
Penny Colton
Barrie Dargie
Dr. Tim de Freitas
Foon Der
Ian DeWolfe
Dr. Steve Donaldson
Dave Drover
Les Eliuk
Dr. Ashton Embry
Dr. Ned Etris
Andrew Fox
Lloyd Freeman
David Garner
Dr. Steve Grasby
Dr. Darcie Greggs
Aaron Grimeau
Dr. Matt Hall
Dr. Tony Hamblin
Peter Harrington
Dr. Peter Hay
Doug Hayden
Greg Hayden
Simon Haynes
Adam Hedinger
Dave Hills
Dawn Hodgins
Peggy Hodgkins
John Hogg
Norm Hopkins
Michele Innes
Dr. Dale Issler
Wim Jalink
Glenn Karlen
Don Keith
Ian Kirkland
Peter Kouremenos
Mike LaBerge
Craig Lamb
Larry Lane
Cory MacNeill
Fraser MacNicol
Ed Mathison
Blair Mattison
Bruce McIntyre
Ben McKenzie
Dr. Margot McMechan
Dr. Dennis Meloche
David Middleton
Jessie Mitton
Guillaume Nolet
Regan Palsgrove
Alice Payne
Brenda Pearson
Dr. Guy Plint
Frank Pogubila
Dr. Brian Pratt
Indy Raychaudhuri
Dr. Gerry Reinson
Dr. Weishan Ren
Jim Reimer
Dr. Claude Ribordy
Dr. Terry Sami
Eileen Scott
Chris Seibel
Claus Sitzler
Randy Smith
Gord Stabb
Dr. Lavern Stasiuk
Dr. Glen Stockmal
Mike Swain
Martin Teitz
Dr. Clint Tippett
Anthony Wain
John Waldron
Dr. Michael Webb
Dr. Hank (Harold)
Williams
Dick Willot
Hugh Wishart
Volunteer Awards for Members who Have Served the Society for Two to Five Years
James Ablett
Linden Achen
Mitch Allison
George Ardies
Dr. Olena Babak
Jeff Barefoot
Julia Baumeister
Tim Bergen
Karen Bradshaw
Charles (Chuck) Buckley
Dr. Jean-Yves Chatellier
Dr. Chris Collom
Andrew Cook
Debbie Cook
Dr. Keith Dewing
Robert Dick
Tina Donkers
Eva Drivet
Bob Earle
Markus Ebner
Dan Edwards
Samantha Etherington
Richard Evoy
Dr. Patrick Fothergill
Jocelyn Frankow
Riona Freeman
Chad Glemser
Tracy Hay
Dr. Fran Hein
Kristy Howe
Carrie Jeanes
Dan Krentz
Shawn Lafleur
Dr. Denis Lavoie
Sid Leggett
Dr. Robert MacNaughton
Dr. Alex MacNeil
Tannis McCartney
Rick McCulloch
Ryan Mohr
Kevin Muir
Dr. Jeff Packard
Dr. John Peirce
Emmanuelle Piron
Kyla Poelzer
Bob Potter
Mark Rabin
Dr. Trent Rehill
Andrew Riben
Sandra Rosenthal
Justine Sagan
Angie Simpson
Heather Slavinski
Tom Sneddon
Meghan Speers
Scott Thain
Cole Webster
Gerald Wendland
Jay Williams
Dr. Andrew Willis
Keith Yaxley
Dr. John-Paul Zonneveld
Reservoir Characterization
Experience, flexibility and cost-effectiveness; combined to deliver to you:
Technically advanced reservoir software • Technically advanced reservoir services • Mapping of lithology, fluids and fractures. •
E XECUTIVE C OMMITTEE SUMMARY
A Year End Review with President, John Varsek
| By Colin Yeo
I sat down with President Varsek to ask him three questions in reflecting back on his presidency. Before I report on his answers, I have to tell readers that this president has been honest, straightforward and transparent in all my meetings with him throughout this year. He not always agreed with what I had to say but he continued to share exceptional insight with me on the debates and decisions of the Executive Committee and I am grateful for the trust he has given me.
I first asked John about the achievements he and the Executive made this past year. As is his usual practice, John started from a high level and he spoke without hesitation. He is most proud that he was able to raise the level of awareness and belief in what the Society could achieve. Remember, the Society had come through two years of turmoil with one crisis after another landing on the Executives’ doorstep and they felt that little overall progress was being made when they had to work so hard just to maintain the status quo. John feels that, in reality, during this last year the Executive has “overcome inertia and got the ball rolling” and “the stage is now set for revitalized leadership.” I asked for evidence of this revitalized leadership and John responded that the Executive has demonstrated an eagerness to tackle both short- and longterm strategic issues and has made performance commitments to the membership and others. Last summer’s budget process tied the annual budget to the Society’s business plan, which in turn was derived from the strategic priorities (Reservoir, February 2010) indicating that the Society is moving forward with conviction and purpose. Becoming very specific, John touched on the inventory of new initiatives the Executive has undertaken, including new programs, a stronger convention agreement for greater profitability and program innovation, moving the convention back downtown, the digital atlas project, plans to reestablish the petroleum assessment committee (a new Canadian Gas Potential Committee but adding oil), web redesign, and a concept to mine 50 years of Society literature and making it relevant for today’s plays.
John is particularly pleased with improved recognition and visibility of members. The revamped awards ceremony is getting traction and attention from the membership, the Under 35 event targeting the next generation of geologists was well received, and the upcoming Volunteer Recognition and Training Day is intended to attract and retain those volunteers who actually run the Society.
But, have there been disappointments during the President’s term in office? “Sure,” said John. “You are there to lead and there are many complex and simultaneous issues to understand and it takes time to formulate plans.”
While the Executive did not ignore any of the big issues facing the Society, it could have focused more of its efforts earlier on core areas. “To illustrate, and these realities are pointed out to us by members, Technical Programs needed greater attention.” The Unconventionals Division (formerly known as Emerging Petroleum Resources) does not have a Chair and, with the prominence of resource plays, this is a very important division to be without a technical
leader. Attendance at Technical Luncheons has been declining since 2006, for reasons not yet well understood. New courses need to be developed immediately for Continuing Education offerings. The CSPG Marketing Strategy was more multi-faceted than initially proposed and depended greatly on starting other renewal initiatives, which meant the Strategy couldn’t be advanced as quickly as intended. These are
(Continued on page 36...)
big issues that are now being tackled and John expects members to see results in 2011.
The performance of the Executive was also part of John’s mandate. There is a need to carefully hone the skills of directors, transforming them from being task orientated to thinking strategically and making sure they understand the responsibilities of their portfolio, while participating in broader Society decisions. John, as Past President, will continue in a mentoring role to set clear expectations and help with training that will result in elevated leadership. This is all part of the renewal process to becoming a stronger, more capable organization.
While bylaw changes were explored this past year, they will be advanced for the membership’s review in 2011. John believes our bylaws need to be updated to make the Society more flexible and efficient. Good progress was made developing the Controversial Issues Policy but this was not finalized.
President Varsek brought forward 33 initiatives (Reservoir, December 2010) during the year so it should not come as a surprise to anyone that some of these initiatives will continue through 2011 and into 2012. The Society simply cannot move faster because volunteers do most of this business and there is only so much time a volunteer can give to the job. Important but
unfinished business has been advanced to next year’s Executive.
I finally asked the President if he had any regrets during the last year.
John regrets what he considers to be an aggressive, disrespectful, and confrontational tone between the Executive and certain groups within the Society that appear to have no intention of constructive engagement to make a better Society. The President pointed out that “the current Executive committed to engage and follow up on all criticism raised by our members. Just look at how the issue of the digital Bulletin rollout was handled to address the issues raised by those involved.” He hopes these very few, but difficult flash points, can be resolved quickly so that the Executive can focus on matters that affect the majority of members.
I came away from our interview with a sense that the President is cautiously satisfied with the progress he and the Executive made during the year. “I never expected all the initiatives to be concluded in one year but only to have made a good start. I am also very pleased with the capacity building in the office, led by Lis, with improved staff skills and new hires that will help us deliver our new renewal strategies. I am also proud of the improvements in CSEG, CWLS, AAPG, and APEGGA dialogue – this will in time, I hope, lead to faster, more aligned, joint programs. Let me also say I view the disappointments and
regrets as opportunities and important learnings for future volunteers to continue building a pertinent and resilient Society. I think this is where most knowledge transfer occurs.”
Of course, President Varsek is a high achiever and nothing less than completing all those initiatives would have made him happy. But perhaps it was more important to have identified all these gaps. After all, you can only change those things you recognize are impeding your progress toward goals. As it is with building a skyscraper, the most important part of the structure is the foundation, which is below ground and unseen and usually unappreciated. But without a strong and stable base, anything built above ground is in danger of collapse. John and his team have built that foundation.
Now it falls to future executives to close these gaps as the President moves on to take his position as Past President, where he will be in a position to advise and guide the new Executive Committee. John says our revitalized Society has attracted other petroleum technical societies who want to partner with the CSPG on projects and events and this, in itself, is an external measure of success. He is delighted that the entire Executive is now focused on “what members want and employers need” and proud of the accelerating rate of positive change within the Society. A can-do attitude now permeates the Executive. And maybe, just maybe, a few of those initiatives can be knocked off the list.
60 TH ANNUAL AUGC at Acadia University
| By Aaron Grimeau and Jacey Seebach
The Atlantic Universities Geological Conference is the longest-running student geosciences conference in Canada, and this year it reached the 60-year milestone. AUGC was held at Acadia University in Wolfville, Nova Scotia from October 28 –30, 2010. This annual conference provides a unique opportunity to bring undergraduate students from the Atlantic Universities together to present their current thesis and research projects, attend field trips on the local geology, and make important peer and industry connections.
AUGC is organized and hosted by undergraduate students. Each year, the conference rotates through the six Atlantic Universities with an Earth Science program. Those universities are Dalhousie University, St. Mary’s University, Acadia University, St. Francis xavier University, University of New Brunswick, and Memorial University. The conference is attended by students and professors from the Atlantic Universities as well as by industry and society representatives.
This year, there were 85 student delegates, numerous professors, and a large contingent of industry representatives, including ExxonMobil Canada East, Nova Scotia Department of Natural Resources, Acadian Mining, The Canadian Society of Exploration Geophysicists, and The Canadian Society of Petroleum Geologists.
The conference was a huge success with eighteen oral presentations and seven posters on topics from Metamorphic Petrology to Environmental Geology and Petroleum Geology. There are several awards for the presenters at the conference. This year’s winners were:
APICS – NSERC Award: Travis McCarron (St. Francis xavier) for his talk on “The Origin and Composition of Polyphase Inclusions in Tourmaline from the Greenbushes Pegmatite, Western Australia.”
Imperial Oil Poster Award: Nor Afiqah Mohamad Radzi (Acadia) for her poster on “Petrography of Stratigraphic Units in the Subsurface of the Phetchabun Basin, Thailand.”
CSEG Best Geophysical Presentation: Matthew Vaughan (Dalhousie) for his presentation on “High Resolution Seismic Stratigraphy (GPR) of Braided Channel Complexes in the Triassic Wolfville
Formation – Controls on Reservoir Heterogeneity.”
Frank Shea Memorial Award: Sarah Gordon (UNB) for her presentation on “The Petrogenesis of Calc-Alkaline Lamprophyres from Mali, West Africa.”
CSPG Best Petroleum Geology Presentation Award: Frank Ryan (Memorial) for his presentation on “Early Jurassic Gordondale Member – Shale Gas Potential and xRD, Wireline Log and TOC Analysis.”
The conference also hosted the Eastern edition of the SEG Challenge Bowl. The winners of this competition won a trip to the CSPG/CSEG/CWLS recovery 2011 conference to be held at the Calgary TELUS Convention Centre in May 2011. The Challenge Bowl was held during the Thursday night Ice Breaker event.
This year’s winners were Anne Belanger and Matthew Vaughan from Dalhousie University.
Other events held in conjunction with the conference were three geological field trips in the Wolfville area, a Ghost Tour of Wolfville, and the Saturday night Banquet and Awards Ceremony.
The AUGC 2010 Organizing Committee (Leah Chiste, Graeme Hovey, Dwight DeMerchant, Nor Afiqah Mohamad Radzi, and Dr. Sandra Barr) would like to thank all of the delegates, representatives, and sponsors for their continued support of the conference.
Any companies / societies wishing to find out more information or to donate to next year’s AUGC, hosted by Memorial University, can contact Sheldon Barron at shb564@mun.ca.
Field trip participants examine interbedded metasiltstone and slate of the Cambrian Halifax Group at Lumsden Dam south of Wolfville.
Jacey Seebach (left) and Aaron Grimeau (right) of the CSPG University Outreach Committee present Frank Ryan (center) with the award for Best Petroleum Geology Presentation.
SQUASH TOURNAMENT MEMORIAL
Cynthia Riediger
The CSPG squash committee has decided to rename its Spirit Award in honor of one of its former participants, Cynthia Riediger. The trophy has been presented annually at the CSPG Squash tournament during the banquet ceremonies on Saturday night. The trophy was created a few years ago by two long-term players, Dell Pohlman and Bruce Shultz, who have been around for this event since its inception. The trophy is awarded to player(s) who display the most spirit during the CSPG Squash tournament. These player(s) are an integral part to a tournament, which focuses
on fun and social networking as well as competitiveness and fair play. Cindy was a great person and competitor on the squash courts. She was a high-ranking women’s A level player for many years. She will be remembered by many of her students who now play in the tournament as well as many friends and colleagues.
“Very sad news, indeed. I remember Cindy as a very engaging and spirited person, and she was so gracious on the squash court. She will be missed in the geologic circles and at the CSPG Squash Tournament. She
was a great participant and was always willing to help out if needed. Her students absolutely adored her,” say Solana Jear and Andrea Henry.
Anyone who knew Cindy would say that this award would capture the essence of who she was. We hope that this award will honor her and help people to remember who she was and what she brought to our community and event.
ROAD TO RECOVERY –recovery 2011 Convention Update
| By Aileen Lozie, Paul MacKay, Rob McGrory, and Satyaki Ray
With only three months to go before recovery 2011 takes place, this year’s convention is in great shape.
C ALL FOR A BSTRACTS
This year’s call for abstracts was very successful. The committee is now tackling placement of presentations in this year’s program and expects to have a completed technical program by mid-March. Continue to check the convention website, www. geoconvention.com for updates!
R EGISTRATION
Registration is now open! The early bird deadline is March 31st, 2011. Avoid disappointment and register early. Events at this year’s convention, including the Core Meltdown, Tuesday Night Reception at the Hyatt Regency Hotel, and the Monday night After-party are sure to sell out! If you have clients, colleagues, or a spouse that are interested in attending the social events, make sure you buy additional tickets when you register to attend.
SPECIAL E VENTS
More details on who is speaking and what items are up for auction at this year’s Light Up the World Silent Auction can be found online at www.geoconvention.com.
Additional tickets for all events can be purchased in advance when you register to attend the convention – so feel free to invite your spouse, partner, co-worker, or potential clients to one or all of the social events.
E ARTH S CIENCE FOR S OCIETY
Exciting News! The Earth Science for Society (ESfS) Outreach Program was such a success last year that it is running it again during recovery 2011. Mark your calendars for Sunday afternoon May 8, Monday May 9, and Tuesday May 10, 2011 to join us at the Calgary TELUS Convention Centre. Admission is free so bring your friends and family and share the Geoscience world with them in a fun and interactive way.
For more information visit: www. geoconvention.com/earth-science-for-society
SPONSORSHIP
E XHIBIT H ALL
Looking to exhibit? Visit www. geoconvention.com for more information on how to submit your exhibitor application. The floor is almost sold out –so act quickly!
C OMMITTEES
The convention’s success relies heavily on the support and dedication of committee volunteers. If you are interested in volunteering for this year’s convention, please e-mail volunteer@geoconvention. com or visit the website for more information.
For more information on this year’s upcoming convention, recovery 2011, please visit the website at www.geoconvention. com or email info@geoconvention.com.
Make sure you register early to ensure you receive tickets for this year’s special events, including Monday night’s icebreaker reception and after-party, Tuesday night’s networking reception, core meltdown, and convention luncheons.
There are several sponsorship opportunities still available for this year’s convention. Ensure your company’s brand is visible at this year’s convention where over 5,000 industry professionals are expected to attend.
Only an unbiased comparison reveals the optimal conveyance method for your formation evaluationneeds.
Maximizing reservoir production while minimizing development costs can be a complex journey. The experts from Halliburton will collaborate with you all along the way, beginning with an approach to formation evaluation that’s free from preconceived acquisition preferences.All methods are considered—wireline, logging while drilling, surface data logging, sub-surface testing, coring or a combination of technologies—with only the most value-added method being proposed.
What’s your challenge? For solutions, go to Halliburton.com/ofe.
