2014 SEG Annual Meeting - E&P [PDF]

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2014 SEG Annual Meeting

OFFICIAL SHOW DAILY PUBLISHER OF THE SEG INTERNATIONAL EXPOSITION AND 84TH ANNUAL MEETING

Spotlighting Advances in Geophysics Innovative technologies include improved imaging, acquisition and migration methods. By Mary Hogan, Associate Managing Editor, Special Projects, E&P

s oil and gas ventures move into ever deeper, more remote and harder-to-access reservoirs both on land and in the sea, the field of geophysics evolves to enable these operations. Many times, geophysics advances take place ahead of the curve, anticipating future exploration challenges. Several experts addressed these ever-changing, innovative technologies during the technical session, “Recent Advances and the Road Ahead,” on Monday afternoon at SEG. Christof Stork of Ion Geophysical looked at “the decline of conventional seismic acquisition and the rise of specialized acquisition.” Seismic acquisition is always a compromise, with cost, logistics and geological objectives impacting it. Seismic data often have Christof Stork inconvenient features, such as noise. “The challenge is how to find the best compromise in acquisition,” he said, adding, “It’s hard, but not impossible.”

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A New Geological Era is Upon Us Bob Raynolds discusses the challenges of the Anthropocene era and the effects it is having on the planet’s ecosystems at SEG’s Applied Science Education Program. By Ariana Benavidez, Associate Editor, E&P

umanity is altering the earth’s natural life systems. “Almost all of the planet’s ecosystems bear the marks of our presence,” according to anthropocene.info. The population is so g reat and is using so many resources that the biology, chemistry and geol- Bob Raynolds ogy cycles by which elements like carbon and nitrogen travel between land, sea and the atmosphere all have been disrupted. Society is now in a new geological era called the Anthropocene, dominated by humanity. “This is everybody’s issue. It’s the issue of our time in many ways, particularly for the scientific community as they’re being called upon to eval-

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See ERA continued on page 27

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He looked at the factors that have changed to enable more specialized acquisition. Acquisition systems are now more flexible, and geological and reservoir objectives are more demanding. In addition, improved old processing allows for more irregular acquisition, and new processing methods benefit from irregular acquisition. Compressive sensing can help achieve more specialized acquisition. The basis of the technique involves the idea that by knowing things about the character of geological objectives and noise and how these influence data, smart compromises can be made with

acquisition. Using the characteristics of geological objectives, artifacts can be removed from acquisition through inversion processing. The signal processing technique can design acquisition compromise using knowledge of the character of geological objectives and noise and inversion processing needs. Using compressive sensing, geophysicists can provide better prestack data quality, less noise and better attribute processing, as well as the knowledge of what attributes are most important in a set of geoSee ROAD continued on page 25

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Getting the Most from Land Seismic High-fidelity acquisition provides more than just structural imaging. Contributed by WesternGeco, a Schlumberger company

il and gas companies are increasingly focusing on developing unconventional hydrocarbon resources, especially onshore, where the cost of drilling wells is usually significantly less than offshore. In tight oil and gas reservoirs, operators have typically drilled a regular pattern of horizontal wells and hydraulically fractured them at regular spacing throughout the lateral. Historical data from unconventional wells have made it increasingly clear that reservoir heterogeneity causes considerable variation in the productivity of individual wells and producing zones, and in situ stress regimes and natural fracture density and geometry play key roles in determining the success of drilling and completion programs. Surface seismic techniques can characterize heterogeneity and measure anisotropy related to localized in situ stress conditions. This knowledge can improve production rates by optimizing well placement and completions strategies. To provide maximum value, a surface seismic survey needs to deliver attributes including high fold, full-azimuth (FAZ) coverage, amplitude integrity and high resolution. High fold helps to maximize signal-to-noise (S/N) ratios. FAZ data are required to map local stress regimes and understand natural fracture networks. Amplitude integrity is essential in determining geophysical attributes such as Poisson’s ratio from prestack inversion to locate sweet spots in the reservoir. Amplitude variation with azimuth can help indicate the orientation of natural fractures. Resolution, both spatial and temporal (hence depth), is always important, particularly when targeting reservoirs that are only a few meters thick. The UniQ integrated point-receiver land seismic system, available for purchase or lease from WesternGeco, provides technology to image and characterize unconventional reservoirs. The system uses Schlumberger broadband geophone accelerometers (GACs). These are high-fidelity low-noise point receivers with highly stable amplitude and phase characteristics that are ideal for amplitude-sensitive studies requiring accurate inversion to derive rock properties, estimate local stress regimes and identify sweet spots. These key capabilities enable UniQ datasets to be optimized to support decisions about well placement and completion strategies. The GACs can be deployed at up to 30.5-m (100-ft) receiver intervals, although many oil and gas companies have instead chosen to take advantage of the efficiency and productivity benefits of the UniQ platform and point-receiver approach to record more densely sampled high-resolution datasets.These typically have a 9-m or 12-m (30-ft or 40-ft) receiver interval, high channel count (e.g., 40,000 live channels) and FAZ acquisition geometries. An increasing number of these densely sampled FAZ projects have been performed outside of the Middle East, the traditional stronghold for such high-capacity surveys. As operators seek to extract new life from harder-toaccess areas of old fields, explore in increasingly complex geologies or look to pinpoint sweet spots in new unconventional acreage, higher channel count denser seismic is becoming the norm. A single UniQ recording system can be scaled to continuously acquire and perform real-time quality control (QC) of any number of active channels. UniQ systems continue to beat industry records with two systems in the Middle East currently acquiring data from more than 200,000 channels on separate projects. At the other end of the scale, a new highly-portable “Micro” system supports up to 5,000 channels and can be operated from a pickup truck. The Micro system retains all the key benefits of its larger sibling and is ideal for fast-moving 2-D operations or realtime surface microseismic monitoring. Operational features of the UniQ system include integrated source control with support

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efficient QC and processing of large datasets. Sichuan Geophysical Co. used a UniQ system to acquire a high-end 3-D seismic dataset to identify sweet spots in a gas shale objective in the Ordos Basin in Central China for Yanchang Petroleum. While the structure is largely flat, a thick surface layer of loess (windblown silt) represents a key challenge for seismic imaging Comparison of part of a legacy 2-D crooked line (left) with Yanchang UniQ 3-D survey prestack time migration in the area. Severely eroded and (right) is shown. (Image courtesy of WesternGeco) of varying thickness and velocity, the loess creates serious for high productivity via Managed Spread and Source static, noise and signal absorption issues as well as technology and full acquisition redundancy with multi- acquisition and logistics challenges due to severe elevapathway automatic data and power rerouting. These tion variations. More than 500 oil wells were pumping, technologies enable low levels of technical downtime and some rigs were drilling during survey acquisition, and record-breaking production rates. Full integration representing additional sources of noise. with the Schlumberger Omega geophysics platform See SEISMIC continued on page 6 >> and Vista desktop seismic processing software ensures

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DA I LY N E W S 1616 S. Voss Road, Ste. 1000 Houston, Texas 77057 P: +1 713.260.6400 F: +1 713.840.0923 EPmag.com

Editor-In-Chief MARK THOMAS Executive Editor/Project Editor RHONDA DUEY Group Managing Editor JO ANN DAVY

SEG

SCHEDULE OF EVENTS Oct. 26 - 31 • Denver

All events will take place at the Colorado Convention Center, unless otherwise noted.

WEDNESDAY, OCT. 29

12 p.m. to 1:30 p.m.

Development & Production Luncheon

7 a.m. to 8 a.m.

Speaker Orientation Breakfast

12 p.m. to 1:30 p.m.

Mining Luncheon

7:45 a.m. to 6:30 p.m.

Committee Meetings Colorado Convention Center and Hyatt Regency

2 p.m. to 3 p.m.

Commencement (SLS and SEP) Student Pavilion, Colorado Convention Center

2 p.m. to 4:30 p.m.

8 a.m. to 10:30 a.m.

Women’s Networking Breakfast

8:30 a.m. to 9:30 a.m.

Guest/Spouse Program: Zumba Class Guest/Spouse Hospitality Suite

Guest/Spouse Program: Crochet Seminar Guest/Spouse Hospitality Suite

6 p.m. to 9 p.m.

Wednesday Night Event Denver Museum of Nature and Science

8:30 a.m. to 5 p.m.

Technical Program Oral Session

9 a.m. to 2 p.m.

Guest/Spouse Program: A Celestial Day in Boulder Meet at Hyatt Regency

THURSDAY, OCT. 30 7 a.m. to 8 a.m.

Speaker Orientation Breakfast

8:30 a.m. to 12 p.m.

Technical Program Oral Sessions

8:30 a.m. to 12 p.m.

Technical Program e-Poster Sessions

9 a.m. to 12 p.m.

Committee Meetings Colorado Convention Center and Hyatt Regency

1:30 p.m. to 5 p.m.

Post-Convention Workshops

7:30 p.m.

Research Committee Dinner Maggiano’s Little Italy located in the Denver Pavilions

9 a.m. to 3:30 p.m.

High Performance Computing Theater Colorado Convention Center, Booth 1582

9 a.m. to 4 p.m.

Senior Editor JENNIFER PRESLEY

Student Pavilion Colorado Convention Center, Hall E

9:20 a.m. to 4 p.m.

Technical Program Poster Session

Executive Editor, Special Projects ELDON BALL

9:20 a.m. to 4 p.m.

Technical Program e-Poster Sessions

10 a.m. to 11 a.m.

Applied Science Education Program

10 a.m. to 12:30 p.m.

Guest/Spouse Program: Crochet Seminar Guest/Spouse Hospitality Suite

11:30 a.m. to 1:30 p.m.

GAC Pacific/Asia Luncheon

FRIDAY, OCT. 31

11:30 a.m. to 1:30 p.m.

GAC Middle East/Africa Luncheon

8:30 a.m. to 5 p.m.

Senior Editor SCOTT WEEDEN

Associate Managing Editor, Special Projects MARY HOGAN

Post-Convention Workshops

Associate Managing Editor, E&P BETHANY FARNSWORTH Associate Online Editor VELDA ADDISON Associate Editor ARIANA BENAVIDEZ Corporate Art Director ALEXA SANDERS

SEG’s Online Education Accessible Anywhere, Anytime SEG On Demand offers a revolving variety of virtual courses, eLearning courses and recordings from the brightest minds in geophysics.

Senior Graphic Designer JAMES GRANT Photography by GARY BARCHFELD PHOTOGRAPHY Production Director & Reprint Sales JO LYNNE POOL Director of Business Development ERIC ROTH Vice President - Publishing RUSSELL LAAS

Editorial Director PEGGY WILLIAMS President and CFO KEVIN F. HIGGINS Chief Executive Officer RICHARD A. EICHLER

The E&P Daily News is produced for the 2014 SEG International Exposition and Annual Meeting. The publication is edited by the staff of Hart Energy. Opinions expressed herein do not necessarily reflect the opinions of Hart Energy or its affiliates. Copyright © 2014 Hart Energy

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Contributed by SEG

ith more than 33,000 members worldwide, SEG continues to evolve and change to meet the growing demand of its global membership. One of the facets SEG continually strengthens is its online educational offerings. With more than two-thirds of its members living outside of the U.S.—and many with limited access to classroom education—SEG strives to provide highquality online education regardless of where members live and work. SEG On Demand (formerly eLearning) offers a revolving variety of virtual courses, eLearning courses and recordings from the brightest minds in geophysics. Every year, SEG compiles video recordings of all technical program presentations for which the instructor has authorized his or her recording; however, this year’s technical program presentations will be available to stream online. All anyone needs is an Internet connection! Containing about 300 technical program presentations with audio recordings, this resource is easy to use and will serve as a valuable reference. To purchase the full conference recordings, individuals must preorder their copy on site at the SEG Denver 2014 registration booth or purchase online at shop.seg.org (Catalog # 2014TPP). After the annual meeting, technical sessions will only be available for purchase by topic. The product will be available three to four weeks after the annual meeting, and learners will have access to the recordings for two years after the product is available. Another area of focus with SEG On Demand is providing online cour ses through the International Human Resources Development Corp. (IHRDC), the worldwide leader in training and competency development for the oil and gas industry.

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Offered through the SEG Professional Development department’s Continuing Education curriculum, the IHRDC courses are online, interactive and cover a wide range of topics. Each course, which lasts from 1 hour to 8 hours, provides users with the much-needed knowledge to increase their level of expertise in their field. Currently the SEG online library boasts more than 170 courses ranging from introductory topics and seismic signals to seismic processing. Another exciting offer from SEG On Demand is the multimodule “Geophysics 101: Seismic Waves in Hydrocarbon Exploration” by notable SEG figure and renowned geophysicist Leon Thomsen. Geophysics 101 is a pilot course designed for students with a general understanding of science and mathematics. The course offers 10 lessons that supply a thorough introduction to the geosciences field, providing future geophysicists and nongeophysicists with a more in-depth understanding of the industry. Currently, six lessons have been completed, and the seventh is underway. To view or purchase a lesson, visit shop.seg.org. Today’s interactive technology has evolved to the point that software and Web applications can present educational content in a for mat that adapts to the evolving skills and understanding of the student, allowing students to test their knowledge or navigate through course materials according to preference. By providing the ability to learn from anywhere, SEG On Demand puts the user in control of his or her own development by providing virtual courses with real-time interaction tailored to an individual pace of learning and a full library of course recordings from the brightest minds in geophysics—all convenient, easy to use and affordable. For more information on SEG On Demand, including all its offerings, visit seg.org/ondemand or email [email protected]. n

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Integrated Workflows for Complex Reservoirs Software platform supports seismic-to-simulation workflows to address challenges in complex operational environments. Contributed by Schlumberger

uring SEG 2014, Schlumberger is showcasing integrated multidisciplinary workflow, using the Petrel E&P software platform, developed to address challenges presented to E&P companies working in complex operational and geological environments. New techniques for solving complex challenges, such as deepwater subsalt exploration, are scheduled to be presented today at the Schlumberger booth. The Petrel platform provides a single, multidisciplinary environment to support seismic-to-simulation workflows while incorporating a wide range of highly specialized functionalities. Users can interpret prestack and post-stack seismic data products, perform well correlation, build reservoir models suitable for simulation, submit and visualize simulation results, calculate volumes, produce maps and design development strategies. By combining a wide range of measurements, oilfield services and interpretation technologies, the Petrel platform reduces uncertainty while increasing the chance of exploration and development success. The upstream oil and gas industry incorporates a multitude of technical disciplines, and the use of multidisciplinary software platforms now informs every key decision in moving hydrocarbons along the pathway from pore space to balance sheet. While individual specialist technologies can deliver impressive results in the short term, a lack of integration is likely to impede a thorough understanding of the reservoir. This can lead to difficulties in mitigating potential problems and developing cost-effective plans over the life of the field. Long-term planning and risk-mitigation are particularly critical in harsh environments such as deepwater fields, where development is expensive and the cost of failure can be high. In the Gulf of Mexico (GoM), operations already are being performed in water depths in excess of 2,133.6 m (7,000 ft), and depth records continue to be broken. Deepwater developments typically cost several billion dollars and have expected lives spanning several decades, during which many decisions need to be made. These decisions address topics ranging from the placement of production and injection wells, well completions strategies and flow assurance to subsea production systems and flowlines. Knowledge that can be extracted from seismic data long after they have been acquired—such as porosity, pore pressures and stress regimes— might provide value when developing contingency plans or addressing unexpected production problems. The Petrel platfor m enables diverse data types and vintages, modeling studies and simulation exercises to be effectively integrated to provide maximum value to support oilfield decisions. Salt provinces around the world present a challenge for seismic interpretation due to the interplay of salt tectonics and evolving depositional history. Identification of mass flow features, delineation of salt bodies and the resolution of subsalt features are just some of the interpretation challenges. A live demonstration is scheduled to take place at 10:30 a.m. today at the Schlumberger booth theater. It will outline powerful new integrated imaging, interpretation and visualization techniques in the Petrel platform to reveal sediments and structures in GoM salt plays. The workflow identifies tectonic and depositional features while incorporating advanced prestack and post-stack imaging products from the Omega geophysics data processing platform and the newly patented eXchroma chromatic geology extraction software. Using these new techniques together with traditional seismic interpretation workflows, sediments and structures can be identified more accurately. The Quantitative Interpretation Suite, part of the Petrel 2014 software release, is scheduled to

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stochastic—are now completely integrated into the Petrel platform, providing geophysicists with a deeper understanding of their data without having to switch software platforms. Well logs, prestack data and seismic inter pretations— such as horizons The Petrel platform was able to combine interpreted seismic, velocity, pore pressure and prestack data in a subsalt prospect and faults contained in the GoM. (Image courtesy of Schlumberger) within a Petrel project—can be easily blended to drive more detailed analysis and insight. be demonstrated at an 11 a.m. Schlumberger booth For more information about these presentations presentation, showing how this new functionality and how other reservoir challenges are being brings advanced geophysical workflows within easy addressed using integrated workflows in the Petrel reach of all geophysicists, not just specialists. Rock software platfor m, go to slb.com/petrel or visit physics, amplitude-vs.-offset modeling and reconnaisSchlumberger at booth 1319. n sance as well as inversion—both simultaneous and

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FWI Hits the Mainstream With widespread adoption, the industry is reaping the benefits of high-resolution velocity models and clearer subsurface imaging. Contributed by CGG

ver recent years, full-wavefor m inversion (FWI) has become a widely adopted seismic technique. It has evolved from a specialist tool to one with applications in many different scenarios and environments. CGG has been at the forefront of this evolution, developing FWI from an academic research application into a mainstream production product. FWI is now an important component of the velocity model-building toolset. FWI uses every aspect of the recorded seismic, including parts that often are removed during conventional seismic processing, so the input data are generally kept as raw as possible. The technique updates the velocity model by minimizing the mismatch between the observed seismic data and data modeled through the current earth model. FWI velocity models are of much higher resolution than those generated by conventional methods, and the FWI velocity models can be as spatially well resolved as the seismic images themselves. FWI provides a step change in the modeling of complex velocity structure, which can be associated

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with the presence of a wide range of geological phenomena such as shallow gas, paleo-channels, suprasalt sediment carapace or permafrost zones. In such cases, the highly variable shallow geology causes shadow zones and distortions in the seismic image. These inevitably hinder the ability to accurately image the deeper earth. The accurate and detailed models produced by FWI can be used by imaging algorithms such as reverse time migration to provide clearer subsurface images, thus facilitating better interpretation and understanding. CGG continues to further refine the FWI processing flow and has developed methods to reduce the artifacts and velocity errors associated with cycle skipping, whereby the algorithm converges on a local rather than global solution. Cycle skipping can be reduced in two ways: Adaptive data selection automatically derives the most suitable offset range and mute parameters without requiring time-consuming manual input, while a probabilistic quality-control technique helps guide the choice of starting velocity model. In addition to velocity, FWI also can assist with the derivation of other seismic parameters. Anisotropy

FWI velocity models contain stunning detail and resolution as seen within this depth slice from a broadband marine survey acquired using BroadSeis offshore Angola. (Image courtesy of CGG Data Library)

(vertical transverse isotropy or tilted transverse isotropy) is needed for most real-world examples and, as such, is included in the modeling of FWI. But now a joint update of velocity and epsilon together can be performed, thereby updating the anisotropy. Also, a high-resolution FWI velocity model can better constrain the area of analysis and convergence of Q tomography, providing superior imaging results. CGG’s role in the continued development of FWI was recognized at this year’s SEG awards. Andrew Ratcliffe, Vetle Vinje, Caroline Win and Graham Conroy of CGG have been distinguished as recipients of the Best Paper in Geophysics award for their technical paper titled, “Anisotropic 3-D Full-waveform Inversion.” The paper was coauthored by Michael Warner, Tenice Nangoo, Joanna Morgan, Adrian Umpleby, Nikhil Shah, Ivan Štekl and Lluis Guasch of Imperial College in London and Alexandre Bertrand of ConocoPhillips Norge. It was published in Volume 78, No.2, March‐April 2013 of Geophysics. For further insights into the latest highlights and developments in FWI, visit CGG at 11:15 a.m. on Wednesday, Oct. 29, at booth 1339 for a presentation by Andrew Ratcliffe. There are also several CGG papers on FWI during SEG technical sessions. Full details are available at cgg.com/seg2014. n

>> SEISMIC continued from page 3 A FAZ (square patch), high-density, highfold, 45,000-channel UniQ survey was acquired over the area. Properly sampled point-receiver fidelity was essential to overcome wavelet distortion problems associated with using conventional sensor arrays in this area. Despite the difficult terrain, average daily production was 921 dynamite shots, with point-source/point-receiver acquisition significantly reducing survey cost compared to a conventional survey. Data processing focused on effective statics and noise solutions. Point-receiver acquisition allowed identification of clear trace-totrace changes in first breaks, helping to build a highly accurate statics solution. Noise attenuation algorithms developed specifically to work on nonuniform data were applied successfully to address the severe noise present in the field data. Prestack time migration further enhanced S/N ratios, taking particular advantage of the high trace density. The results from the new survey showed significant improvement in imaging clarity compared to legacy data from this area of complex geology and logistics and were achieved cost effectively. For more information, go to slb.com/uniqsales or visit Schlumberger at booth 1319. n

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Dynamic Solutions for Unconventional Plays Platform provides a unified analysis, interpretation and modeling system. Contributed by Landmark, a Halliburton company

rofit margins in unconventional resource plays remain thin while the complexity and velocity of operations continue to rise. In some plays, a high percentage of perforations contribute little or no hydrocarbons to production. Since shale wells typically undergo rapid declines, the only way to sustain economic production is through increasingly aggressive drilling and completion activity. As the intensity of operations escalates, however, shale operators might be reaching the limits of efficiency possible through innovations in horizontal drilling and hydraulic fracture engineering alone. “To achieve the ROI [return on investment] that companies require today, greater collaboration across disciplines is increasingly critical as well as more rigorous subsurface modeling and high-intensity well planning tools to target sweet spots efficiently and automatically,” said Bill Ross, director of geological and geophysical frameworks for Landmark. Landmark’s DecisionSpace platform provides a single integration infrastructure to access the myriad of measurements—and databases—used in unconventional operations. It blends data management with applications in geophysics, geology, drilling, completion and production engineering to provide a unified analysis, interpretation and modeling system. “The DecisionSpace platform is the only multidomain workspace capable of handling the data growth swamping unconventional assets,” Ross said. Once an effective means of integrating asset data is available, it is possible to create a high-definition digital subsurface model. However, this is not yet common in unconventional plays, Ross said. The engineering issues have received much more attention than the geology. “One of the biggest overlooked problems is how to keep the subsurface model fresh and relevant when so much new infor-

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With Dynamic Frameworks to Fill workflow technology, new well and seismic data automatically refine the subsurface model, enabling operators to target sweet spots more precisely in subsequent wells. (Image courtesy of Landmark)

mation keeps pouring in from the field, often in real time,” he added. Every additional wellbore provides not just a new data point but a whole new dataset. The DecisionSpace environment includes the Dynamic Frameworks to Fill modeling technology. It enables geoscientists and engineers to efficiently incorporate new information into a multisurface 3-D structural framework model that never gets out of date. “What differentiates the Dynamic Frameworks to Fill workflow is that we designed it from the ground up to update automatically,” Ross said. The system actively “listens” for new well data, geologic interpretations and newly interpreted seismic information. It has an intelligent topology engine that automatically calculates 3-D intersections among horizons, faults and unconformities and then properly trims and seals them against one another. Every surface in the sealed framework is dynamically linked to every other surface, and a single change triggers an instantaneous update to the entire model. “As a result, the model ‘learns’ and continuously improves with each well drilled, which makes it ideal for fastpaced unconventional drilling campaigns,” he added.

By integrating this evergreen 3-D framework with earth-modeling technology, the DecisionSpace environment also allows geoscientists and reservoir engineers to populate or “fill” it with static or dynamic rock and fluid properties. According to Ross, automated updating can accelerate mapping workflows by an order of magnitude— even in conventional plays. “One operator needed to map 10 unique reservoir properties over 14 distinct intervals based on data from thousands of wells,” he said. “By replacing traditional gridding macros and property mapping techniques with Dynamic Frameworks to Fill workflows, geoscientists reduced the cycle time for each model update from two or three days to 15 minutes.” In unconventional plays with hundreds of wells, thousands of data points and multiple stacked reservoirs, this technology can be even more valuable. Operators can keep pace with aggressive drilling schedules, update the 3-D framework and maps with real-time LWD data and geosteer the drillbit to stay in the sweet spot. To plan all those wells, operators also are turning to DecisionSpace Well Planning software, which can seamlessly integrate geology and a geographic information system with directional dr illing data. Automated multiscenario field planning, visualization and optimization tools can enable teams to rapidly design and refine pad locations, well spacing and complex trajectories. All workflows take place within the context of the dynamic 3-D framework, surface topography and user-designated “no-go” zones while adhering to rigorous drilling engineering constraints. “By running multiple full asset DecisionSpace Well Planning scenarios, one large independent operator increased reservoir contact by more than 10,000 ft [3,048 m] in its shale asset while simultaneously eliminating 16 wells and 22 pad locations from the original drilling plan,” Ross said. “This saved millions of dollars in capital investment and dramatically reduced the operator’s environmental footprint.” n

OBS Is Key for Challenging Marine Environments Seismic method can yield reliable data in hard-to-reach areas. Contributed by Seabed Geosolutions

oday’s global search for hydrocarbons takes place in some of the world’s most difficult environments. While conventional 3-D streamer acquired seismic surveys are the basic way to acquire subsurface data offshore, there are locations and conditions where acquiring a seismic survey using long streamers is not safe, technically adequate or practical.These areas include transition zones; shallow waters; and obstructed, high-traffic or congested waters. Other challenges arise when hydrocarbons are obscured by presalt or gas clouds. For these targets, directly measured shear (converted) wave and pressure wave information is the best way to image the subsurface. The experienced field crews and fourcomponent (4-C) ocean-bottom technologies of Seabed Geosolutions are uniquely qualified to overcome the difficulties of conducting surveys in these and other challenging environments in water depths ranging to 3,000 m (9,842.5 ft). With more than 25,000 sq km (9,653 sq miles) of seismic data acquired in some of the world’s harshest conditions, Seabed Geosolutions offers technologies that can safely and efficiently acquire high-quality subsurface seismic data. For example, the transition zone between land and marine seismic operations encompasses some of the most remote, sensitive and congested environments on Earth. An ocean-bottom seismic (OBS) solution is a reliable, proven way to seamlessly tie in a land survey with a survey that transitions to offshore. With more than 100 transition zone surveys recorded worldwide, the company’s suite of OBS

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technologies can yield reliable 4-C data in these hard-to-reach and environmentally sensitive areas. A dedicated fleet of purpose-built, shallow draft vessels carrying versatile ocean-bottom receiver technology and shallow airgun source equipment leaves no environmental footprint. The company’s lightweight vessels, which also are highly maneuverable, can be used in areas with high traffic or busy fishing activity. Without multiple kilometers of streamers in tow, an OBS survey in these areas can be acquired safely with lessened risk of downtime, damage to the spread or disturbance to commercial activities in the area. While OBS is the most logical solution for shallow water and transition zones, its efficiency does not stop there. Moving into intermediate and deeper water, weather and currents can play a major factor in the acquisition of a seismic survey. Using OBS in areas with known currents and strong wave action can be a safer and more reliable choice, with no risk of out-ofspecification streamer angle, too much feather, excess noise or excessive weather downtime. As long as the source can run, the survey can continue. An oceanbottom survey in these conditions can offer data acquisition with less noise, no infill and simplified multiple removal during processing. Obstructed areas are an obvious choice for an ocean-bottom solution. Ocean-bottom technologies can be safely and precisely positioned in heavily obstructed fields close to infrastructure, providing the ability to collect high-quality full-azimuth long-offset datasets in areas where it is impossible to navigate with large streamer spreads.The receiver location also can be accurately repeated in future monitor surveys, making the systems ideal for 4-D life-of-field management.

OBS technology is ideal for congested areas with high traffic or busy fishing activity. (Image courtesy of Jean Batiste Chalvidan)

Additionally, OBS systems can be deployed in an ad hoc basis for a small, densely shot area whereby the target needs special geophysical focus, such as imaging below presalt or when the objective is obscured by shallow gas. This ad hoc technique also is beneficial as a tie-in with streamer data for undershoots, guaranteeing data with no infill (compared to streamer seismic), a higher proportion of near offsets and fullazimuth coverage. The company’s geoscientists can help evaluate and design a survey that takes into consideration the local terrain, HSE constraints, permits and regulations, the illumination of a chosen target, and budget. The company’s seabed imaging technologies include ocean-bottom nodes and ocean-bottom cables. Visit Seabed Geosolutions at booth 1124 for more information. n

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Quantitative Seismic Interpretation of a Gas-Bearing Reservoir Integrating seismically derived elastic attributes and rock physics analysis to characterize and delineate a gas-bearing reservoir. By Pedro Alvarez, Francisco Bolívar and William Marín, Rock Solid Images

ne of the aims of quantitative interpretation is to predict interwell reservoir properties by leveraging information from rock physics models and seismic attributes. This methodology was successfully applied in fluid prediction within mudrich deepwater turbidities. As a direct result of this reservoir characterization study, two new locations were drilled in the field, both of which penetrated producing levels and were since classified as discovery wells. This successful result allowed Rock Solid Images (RSI) to validate the current workflow and update the geological, geophysical and petrophysical model for the future exploration and exploitation plans in the area. The project was undertaken in three phases. In the first phase, well log and rock physics analysis was conducted. One of the earliest and most important steps to integrate well data for a seismic reservoir characterization is an integrated analysis of the log curves over the full wellbore. This includes standard petrophysical volumetric estimation (lithology, porosity and fluid content) and well log conditioning based on rock physics diagnostics. The resulting conditioned logs and volumetric estimation were used together with rock physics models to evaluate the relationship between petrophysical and elastic properties in the cross-plot domain (Figure 1a). From this rock physics template analysis it was possible to recognize that gas-bearing shaly sands tend to have lower P-wave impedance (Ip) and Poisson’s ratio (PR) than wet sands and shales. Phase 2 involved performing gather-conditioning and prestack simultaneous inversion following the approach of Singleton (2009) and Tonellot et al (2001), respectively. Signalto-noise ratio, offset-dependent frequency loss and gather alignment were addressed in the gather-conditioning. The data used as input for the seismic inversion were partial-angle stacks, extracted wavelets per angle stack, and Ip and Is low-frequency models (LFM). The LFMs were built by combining calibrated seismic interval velocities with upscaled well data. Figure 1b shows a cross section through the resultant seismically der ived PR cube along two of the wells drilled in the area. Notice the good match between the seismic and well-log derived PR attribute as well as the expected relationship between zones of low PR and gas-bearing sand. Phase 3 involved pay sand characterization and delineation. Rock physics analysis allowed the company to identify the differences between pay and nonpay zones based on their elastic properties. This analysis allows the company to establish the cutoff parameters for the isolation of the gas-bearing sands using a polygon-based cross-plot approach. Figure 1c shows the resultant geobodies associated with zones with high probability of being gas-bearing sand. Most of the highlighted geobodies are confor mable with structure and are located updip, adding confidence to the results. Next, the resultant geobodies were filtered to eliminate noise and keep only the larger and connected geobodies. Then, a thickness map in time was calculated and converted to depth using a velocity model (Figure 1d). This final map, which rep-

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resents a net pay map for the target formation, was used to estimate the net pay volume and can be used to reduce risk in the dr illing of new wells in the field. For more information on this project or workflow, contact Pedro Alvarez at [email protected] or visit RSI at booth 2538 at SEG. n

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Figure 1. (A) A rock physics template shows the relationship between the petrophysical and elastic properties in the cross-plot domain. (B) A cross section through the resultant seismically derived PR cube along two of the wells drilled in the area is shown. (C) Resultant geobodies associated with zones of high probabilities of being gas-bearing sand are shown. (D) A net pay map for the target formation is highlighted. (Image courtesy of Rock Solid Images)

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Differentiating Between Dolomites and Limestones Seismically derived photoelectric index volume can be used to characterize dolomite reservoirs. Figure 1. A cross-plot between P impedance and S impedance that is color-coded with Pe values is shown. A) The blue and red ellipses enclose the points corresponding to low and high values of Pe corresponding to dolomite and limestone, respectively. A crossplot between LI and Pe for well log data in the zone of interest that is color-coded with density values is demonstrated. B) The scatter of points exhibits a linear relationship. The blue and red ellipses enclose the points corresponding to low and high values of Pe corresponding to dolomite and limestone, respectively. A horizon slice from inverted Pe data is shown. C) The predicted response correlates fairly well with well data. (Image courtesy of Arcis Seismic Solutions)

By Ritesh Kumar Sharma, Satinder Chopra and Amit Kumar Ray, Arcis Seismic Solutions, TGS

arbonate sedimentary rocks that have been dolomitized and laterally sealed by tight undolomitized limestone frequently produce hydrocarbons. Compared with clastic reservoirs, the character ization of dolomite reservoirs presents challenges as many of the conventional methods, comprising attributes such as Lambda-Rho and Murho, are not very effective. Consequently, alternative methods are needed for the characterization of Upper Ordovician Trenton and Black River carbonates in eastern Canada as well as the ability to map the lateral extent of dolomite reservoir rocks that have a thickness below the seismic resolution. While making measurements in the wells, the latest density logging tools make it possible to differentiate between dolomites and limestones using the photoelectric index log. The tool has a gamma ray source that emits radiation, which enters the formation (by about an inch or so), gets scattered and loses energy. The intensity of the backscattered radiation is picked up by the detectors installed on the tool. While the higher energy part of the backscattered radiation is related to the density, the low-energy component is a measure of the average atomic number of the formation or the rock matrix properties (lithology). Fluids have very low atomic numbers and so have little influence. The limitation, however, is the availability of Pe (photoelectric index) curves only at well locations. Arcis demonstrates an integrated workflow in which well data and seismic data from eastern Canada are used to discriminate between limestone

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and dolomite. The workflow begins with the generation of different attributes from the well log curves. As shown in Figure 1a, using the cross-plot between P impedance and S impedance, color-coded with Pe values, the blue and red ellipses are drawn corresponding to points that have low and high values of Pe to identify the dolomite zones. Instead of using these two separate attributes, it is possible to differentiate between limestone and dolomite by rotating the clusters in a counterclockwise direction. Such a rotation leads to new attribute, namely lithology impedance (LI) that incorporates the lithology formation and can be defined as LI = IP *sinθ - IS *cosθ, where θ is the angle of the regression line intersection with the horizontal axis (Figure 1a). The purpose of generating this attribute is to be able to use a single attr ibute for distinguishing the dolomites from limestones. Next, to be able to derive the Pe attribute from seismic data, Arcis investigated the relationship between the LI and Pe well log curves, which can See DOLOMITES continued on page 22

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Redefining Seismic Inversion Bayesian inversion system can work with both sparse and dense well control and can be operated within reasonable time constraints. By Michel Kemper, Ikon Science

eismic inversion aims to extract rock properties such as porosity, saturation and Vshale from seismic. Seismic, however, responds to changes in impedance at the interface of two formations, so the seismic inversion challenge breaks into two steps (even though it is sometimes “hidden” in one application): (1) obtaining from seismic the impedance of each interval, which is known as seismic inversion; and (2) deriving rock properties from these impedances, which is known as reservoir characterization. Reservoir characterization relies on per-facies rock physics modeling, with the facies being an elastic-seismic facies such as shale, water-sand or gas-sand.

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Today’s technology Even though in step 2 it is common practice to derive rock properties per facies, to date seismic inversion algorithms overwhelmingly invert for impedances only, i.e., not per f acies—even though seismic modeling conclusively shows that facies transitions form a primary control on the impedance changes that in turn control the seismic response. The exception is certain laborious geostatistical algorithms that do invert to facies and impedances per facies. However, these have certain shortcomings: They require a relatively dense amount of well control; typically use variography, which is not suited to the simulation of facies; and can take weeks, if not months, to set up and run.

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Ji-Fi As the name indicates, joint impedance and facies inversion (Ji-Fi) performs the inversion for both facies and impedances per facies. Ji-Fi, therefore, fully captures the physics of the seismic inverse problem. Compared to today’s technology this leads to: • Better impedance Figure 1. Net sand determined from facies models from an oil and gas field offshore Western Australia is estimates; • A more consistent shown. At left, the facies model is obtained by Bayesian classification on simultaneous inversion derived facies model of impedances. At right, the facies model is Ji-Fi derived. The model shows that the Ji-Fi results match the five great help to geo- wells, the Ji-Fi derived channel is continuous and that Ji-Fi predicts water-bearing sands off structure. modelers (as com- (Image courtesy of Ikon Science) pared to facies models obtained using Bayesian classification— Results Ji-Fi has been operated on a number of hydrocarsee Figure 1); and • Improved reservoir properties as steps 1 and 2 bon assets, and the results are impressive (see Figure 1). In some cases where no well control are now both facies-based. Ji-Fi is a Bayesian inversion system that supports was available within the area of the seismic surthe control of lateral facies continuity and inhibits vey, per-facies trend information derived from facies transitions that are not geologically or hydro- nearby wells or even per-facies analogue trends logically plausible (e.g. water-sand on top of gas- were used to initiate the process, with surprissand). It works equally well with sparse or dense ingly good results. Ji-Fi will be commercially available beginning well control and can be operated within reasonable Dec. 1, 2014. Attendees can visit with Ikon Science time constraints. The Ji-Fi method is the culmination of four at booth 1208 to pick up the recent article by Dr. years of research in partnership with Australia’s Michel Kemper and Dr. James Gunning that was of conventional bandwidth inversion2014 (top) and broadband inverpublished in the September issue of First Commonwealth Scientific and Industrial Research Comparison sion (bottom) is shown. (Data courtesy of Dolphin Break or for a demonstration. n Geophysical Multiclient) Organization and with funding from Tullow Oil. W E D N E S D A Y | O C T . 2 9 , 2 0 1 4 | E & P DA I LY N E W S

Disk Drives Are (Relatively) Cheap. People’s Time Isn’t. Changing the way seismic compression technology is adopted by the industry involves balancing compression quality and performance. Contributed by Hue

he oil and gas industry has long had a keen interest in seismic compression. Copious quantities of research have been published, but uptake has lagged. Hue, mostly known for its visualization and GPU acceleration technologies, aims to change that. Seismic datasets keep increasing in size and resolution, and it’s not uncommon to see double-digit terabyte size surveys today. The challenges of managing such large volumes have prompted academia and industry experts to conduct and publish research on the topic. Compression is attractive for several reasons. If data can be compressed in the field (during acquisition), less data have to be transferred for in-house processing and analysis, making data available earlier for decision making. In processing and imaging, it’s attractive to compress data to increase the throughput of the compute system (cluster) due to band-

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width ceilings in data transfer. In an exploration setting, teams need to condition and interpret these huge surveys, and although a lot of time can be wasted on data-copying of uncompressed data, that implies less time available for real work. People’s time is not cheap. Much of the research has focused on the quality and appropriateness of compression. As a result, there are now recommendations and standards for data compression both in oil and gas as well as other industries. The key reason for the lack of use of data compression isn’t quality. Rather surprisingly, perhaps, the key reason has been that the compression (and subsequent decompression) has simply been too slow to be of great value. For that reason, most compression used today is for long-term storage, but this does little to help address the benefits that the industry wants. Hue has, over the past eight years, carried out a lot of R&D on data compression techniques, and the

company believes it has achieved an optimal balance of compression quality and compression performance. The technology is integral to the company’s visualization and GPU acceleration product, HueSpace, but given the excellent results the company has decided to commercialize the data compression and corresponding multidimensional file format for wider adoption. Why is this becoming more and more relevant? The increased acquisition of full-azimuth/wideazimuth (WAZ) and 4-D life-of-field seismic implies that seismic datasets have become a real logistical problem. The increasing sizes of the data pose great challenges to the exploration divisions, where seismic data account for up to 90% of enterprise storage demands. Geoscientists working with seismic processing applications face challenges when trying to access the data, since large files can cause performance issues when trying to access such datasets from semilocal databases or central storage. This leaves no other choice than to copy the data to the workstation or workg roup ser ver instead. Unfortunately, as one senior geophysicist found out, copying 40 terabytes of WAZ seismic from the high-perfor mance computing fast storage to the local workgroup server would take weeks. As a consequence, a lot of data—especially prestack data—goes uninterpreted. As mentioned earlier, geoscientists apply a large number of algorithms during interpretation and characterization, creating even more data. For example, it’s not uncommon for users to export spectral decomposition volumes from nine different frequency bands. With newer technologies such as HueSpace, these data could be computed on the fly and never stored, but in many legacy packages such attributes need to be precomputed prior to analysis. Exporting these introduces a significant and unnecessary strain on disk and networks. Cur rent practices in inter pretation and derisking involve extensive attribute analysis, reservoir characterization from direct hydrocarbon indicators or amplitude vs. offset, and inversion studies. This implies that input data must be adequate for quantitative purposes. Not all seismic compression methods guarantee true amplitude, and that is crucial for any quantitative workflow. Oil companies making use of software that contains seismic compression need to ensure that any data compression is trustworthy, as several published papers have indicated possibilities of skewed results deriving from changes in phase, frequency or amplitude. Data compression isn’t lossless, but the loss should not affect subsequent use. Supermajors, nationals and independent software vendors (ISVs) working with Hue have already conducted rigorous analysis and benchmarking of the compression technique. What triggered Hue to commercialize its compression technology was additional benchmarks with key industry software where Hue’s software was found to provide superior results, resulting in significantly smaller files and spending far less time on input/output and compression. Hue’s technique turned out to be almost 25 times faster than the compression recently introduced to a prominent software package. In this particular benchmark, Hue’s technology compressed the entire 24-gigabyte North Sea Quad in less than 2 minutes on a regular laptop PC. Oil companies and ISVs interested in discussing usage and licensing can visit with Hue at booth 462. n

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Multi-array Microseismic Monitoring Improves Quality, Quantity of Data Collected Technology provides improved reservoir characterization and understanding of fracture development during reservoir stimulation in unconventional formations. Contributed by ESG Solutions

n hydraulic fracturing operations, achieving maximum production along an entire well depends not only on effective well placement and completions design but also on the inherent characteristics of the reservoir. Ideally, well placement and completions designs are tailored to specific reservoir conditions; however, considerable formation heterogeneity coupled with a poor understanding of the subsurface often are cited as key challenges for producers in maximizing production from hydraulic fracture stimulations. In many instances where wells were treated identically, operators have demonstrated cases where hydrocarbon production rates vary not only between wells in the same field but also between stages along the same well. Operators rely on a number of geophysical tools to make critical decisions regarding current and future hydraulic fracture treatments, one of which is microseismic monitoring. They also rely on micro-

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Multi-array microseismic monitoring offers the potential for advanced microseismic analysis of fracture behavior and delineation of effective fluid flow pathways (stream lines) within a stimulated reservoir. (Image courtesy of ESG Solutions)

seismic results to characterize reservoirs, infer stimulation success or provide inputs to reservoir models, so it is imperative that the best available information is at their disposal. Microseismic programs are designed to address specific needs and goals; however, the amount and quality of data can be affected

by factors such as deployment method, acquisition equipment, formation geology, monitoring well location and well condition. One way to help maximize the value of microseismic investments is to deploy multiple arrays around a target treatment zone. This can be accomplished in a number of ways, including by deployment of multiple vertical or horizontal arrays in separate monitoring wells, deployment of ESG’s Whip-array or deployment of complementing downhole arrays with the addition of near-surface sensors in a hybrid configuration. Multi-array deployments can considerably improve the quality and quantity of microseismic data collected. The rise of pad drilling provides many more options for downhole monitoring by making use of adjacent laterals as temporary observation wells. Alternatively, innovative approaches such as the Whiparray deploy two geophone arrays simultaneously into the horizontal and vertical sections of a horizontal observation well—a solution that maximizes both event detection ranges and location accuracy. In one example in a North American shale play, data acquired using a Whip-array during hydraulic fracture stimulation was evaluated and compared to microseismic data acquired using a single vertical array. The use of the Whip-array configuration resulted in 39% more events being detected while improving average event location accuracy by 19%. Using multiple well arrays helps reduce microseismic location error resulting from uncertainties in arrival times, hodograms and velocity models by introducing several independent constraints on event locations. Perhaps the least recognized but potentially most powerful application of multi-array microseismic monitoring relates to the ability to use information contained within full seismic signals to improve understanding of subsurface conditions, reservoir properties and fracture development processes. A key advanced processing technique that has emerged within the microseismic industry and which is driving much of the recent innovation in understanding reservoir behavior is seismic moment tensor inversion. Requiring high-quality multi-array microseismic data, the method connects seismic observations of a discrete event to the physical processes at the source that are causing the event, such as the event failure mechanism, principle strain axes and potential failure plane orientations. Since microseismicity might be fluid-induced or caused by changing stress conditions in the reservoir, not all seismicity will contribute to production. Using advanced multi-array microseismic processing methods, it is possible to generate a discrete fracture network (DFN) model describing fracture networks that have been activated during stimulation. While this activated DFN can provide better estimates of true stimulated reservoir volume and fracture connectivity, the use of a geomechanical model of strain imparted on the rock mass enables visualization of likely fluid flow paths through the reservoir. Overlying this analysis with calculated seismic deformation and fracture complexity within the reservoir then provides some indication of reservoir drainage and ultimately insight into reservoir production. Microseismic methods can offer key understanding of reservoir characteristics and fracture development following hydraulic fracture treatments. In many cases, multi-array microseismic monitoring helps operators maximize the value of their microseismic investment. Ultimately, determining how to acquire microseismic data depends on the needs and goals of the program and an understanding of which monitoring configuration will satisfy these needs. For further information, visit ESG Solutions at booth 2348. n

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Cablefree and Real-time Seismic Recording Data collection system experienced success in Kurdistan despite rugged terrain, nearby conflicts and high temperatures. Contributed by Wireless Seismic Inc.

n 2013, Asian Oilfield Services Ltd. (ASIAN), based in Gurgaon, India, acquired its largest 3-D survey to date for Russian oil company Gazprom Neft, operator of the Shakal Block in the autonomous region of Kurdistan. The project was set against the backdrop of rugged mountainous terrain, searing desert temperatures and less than enthusiastic locals from surrounding villages, mixed with the occasional minefield left over from previous conflicts. Based on Gazprom Neft’s technical requirements, ASIAN chose to deploy Wireless Seismic’s RT System 2. Despite all the challenges, the project was most notable for acquiring data with a spread of more than 6,200 live channels with real-time transmission of all the seismic data—setting a new world record for the largest number of live seismic channels recorded in real time by a cablefree seismic data acquisition system. Gazprom Neft was so impressed with the real-time performance of RT System 2 that it asked Wireless Seismic Inc., based in Sugar Land,Texas, to test the system in the extreme frozen conditions of the Siberian forests earlier this year. The test results fully justified all of its expectations, including improving overall productivity. It has led Gazprom Neft to champion the “green seismic” technique in its efforts to improve the environmental impact of seismic surveys. A second oil company contracted ASIAN to return to Kurdistan this year to acquire a 3-D survey that covered a larger area and encountered the same hostile terrain and environment. Supported by Wireless Seismic’s field service engineers, ASIAN quickly surpassed its previous record by deploying more than 13,000 channels and setting another world record for cablefree, real-time data transmission from a live patch of more than 6,400 channels.

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In mid-August, production was disrupted by an earthquake, measuring 6.2 on the Richter scale, close to the Iranian-Iraqi border. RT System 2 was able to monitor the background seismicity due to aftershocks and inform the user’s decisions to cease production when the tremors occurred. The RT System 2 real-time capabilities have been put to use in far more dramatic ways because the increase in the Islamic State of Iraq and Syria (ISIS) activities, not far from the survey area, resulted in conflict between ISIS and the Kurdish Peshmerga. Noise generated by the artillery bombardment between the two sides was moniA worker deploys an RT System 2 wireless remote unit in the rugged terrain of Kurdistan. (Image courtesy tored by the RT System 2, which despite being out of earshot, of Wireless Seismic Inc.) swamped the seismic records. The system’s real-time QC was able to see clearly the RT System 2 delivered excellent productivity extraneous noise on the spread, and the user was able due to its stability and because it was consistently to pause production until the bombardment ceased. live, ready and waiting for the vibrators at the “The real-time monitoring capabilities of the RT beginning of each day. The system helped to optiSystem 2 have played a significant role in Kurdistan mize data quality, as its real-time quality control this summer,” said Mick Lambert, Wireless Seismic (QC) was able to monitor the effects of wind president and CEO. “Our client was able to maxinoise over the spread. This allowed the user to mize productivity by being confident that the system decide when to pause acquisition. It also helped to was properly deployed, and it was able to distinguish improve ground coupling by identifying poor geonormal environmental disturbances as compared to phone plants—a significant problem in Kurdistan’s earthquake and conflict-generated noise. These latter arid rocky terrain. events were out of earshot, and the system’s areal Occasionally, some of the wireless remote units SeisMonitor proved to be a huge benefit, saving the were stolen during the survey. However, because the client from having to reshoot data acquired outside RT System 2 transmits data in real time, only the acceptable noise specifications.” hardware was stolen—the much more valuable data To learn more, visit Wireless Seismic at booth 908. n were already safely stored at the central recorder.

9th SEG Annual Meeting Challenge Bowl

MicroSeismic Inc. CEO and Challenge Bowl founder Peter Duncan presented a check and congratulations to the 2014 Challenge Bowl winners on Monday afternoon at the Hyatt Regency. The top team included Bartosz Gierlach, from the AGH University of Science and Technology, and Paulina Kotlarek, from Adam Mickiewicz University.

The Challenge Bowl runnersup team from the Universidad Nacional de Colombia Sede Medellin received their awards from Peter Duncan. Shown are León Fernando Ramirez Hoyos (left) and Jose David Henao Casas. The annual Challenge Bowl competition tests students’ knowledge about geoscience. (Photos by Barchfeld Photography)

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Societies Announce Continued Collaboration AAPG reaches another milestone with its support of GWB. By Rhonda Duey, Executive Editor, E&P

he Geoscientists Without Borders (GWB) program is one of the most far-reaching programs supported by the SEG Foundation. Soon it will have a little help from outside. During the annual Foundation luncheon, it was announced that the program would soon receive joint funding from the American Association of Petroleum Geologists (AAPG) Foundation. “We always thought it would grow beyond the boundaries of SEG,” said Rhonda Jacobs, GWB program manager. “It was in our vision that AAPG would be one of our prime partners.” David Curtis of the AAPG made a few comments regarding the decision. “We are proud to announce that we’re going to become associates within GWB, which is one of the largest partnership levels,” Curtis said. “I commend SEG and the Foundation for its vision in developing this program, which goes

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beyond the industry and has a humanitar ian focus. We’re really looking forward to bringing geology to GWB.” Geoscientists Without Borders supports humanitarian applications of geoscience around the world. Goals include providing funding to projects that will benefit communities in need, where applying geophysical sciDavid Curtis ence and information is critical to improving poor conditions or where dangerous conditions and hazards can be mitigated or removed using applied geoscience technology; strengthening the global geophysical community through beneficial multidisciplinary partnerships and cooperation with other organizations active in engineering and geoscience; and strengthening and encouraging SEG student chapters by energizing students and introducing

them to the broad range of geosciences careers while also strengthening university programs in geophysics and the geosciences. Former SEG President Craig Beasley, who initiated the program during his term, was awarded honorary membership during Sunday’s Honors and Awards presentation for his work on the program. This is just the latest in a series of new collaborations between the two societies. Already they work with the Society of Professional Engineers to put on the Unconventional Resources Technology Conference each summer, and they take turns editing the new journal Interpretation. Most recently the two societies have announced that they will jointly manage international conferences. “It’s important to recognize the leaders of both organizations who have really made this possible,” Curtis said. “We’re excited. This is one more step to take the constituents of our two organizations and together advance geosciences.” n

EXPEC ARC Geophysics Shares Strategic Research Technology initiatives focus on automation, multigeophysics and bringing geophysics closer to the reservoir. Contributed by Saudi Aramco

he Saudi Aramco EXPEC Advanced Research Center (EXPEC ARC) Geophysics Technology unveiled key strategic research directions and achievements during a special event at the Hyatt Regency on

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Monday morning. Panos Kelamis introduced three major technology initiatives: automation, bringing geophysics closer to the reservoir and multigeophysics. Automation seeks to improve efficiency and data quality while reducing cost in seismic data acquisition, processing and interpretation. Constantine Tsingas presented a major industry collaboration currently underway to build a commercial automated shallow-marine seismic acquisition system using AUVs that can be easily positioned and retrieved anywhere on the seabed. Panos Kelamis welcomed SEG 2014 attendees to a special event Monday morning that The introduction of highlighted Saudi Aramco’s EXPEC Advanced Research Center’s research strategy and robotization and automa- achievements. (Photo courtesy of Saudi Aramco) tion in the seismic value for continuous CO2 monitoring. Future usage of chain will be one of the key enablers to a more extensive buried seismic acquisition or in situ seismic will use of seismic data, particuinclude targeted reservoir characterization and conlarly offshore multicompotinuous monitoring. Cheap drilling, smart sensors, nent seismic and monitoring powerful sources and efficient deployment are key applications over large fields building blocks that require fit-for-purpose develonshore. To handle the resulting opment to cover significant areas of interest. In situ large data volumes, new techseismic will complement surface acquisition and nologies are being developed to will enable high-fidelity reservoir geophysics appliautomate seismic processing/ cations in challenging land environments with a imaging and interpretation complex near-surface. including velocity analysis, statMultigeophysics aims to develop cutting-edge ics and inversion as well as technologies for joint inversion of multigeostructural and fault mapping. physics data for seismic imaging and reservoir The topic of br ing ing monitoring applications in giant carbonate resergeophysics closer to the voirs and complex offshore exploration plays. reservoir aims to dramatically Integration of electromagnetic (EM) and seismic improve seismic data fidelity data already provides a significant uplift in conand increase vertical resoluventional seismic imaging workflows. Daniele tion. Andrey Bakulin disColombo explained how EXPEC ARC has develcussed how sensor s and oped world-class capabilities in EM and gravity sources will be buried below modeling/inversion for land and marine applicathe surface in deeper obsertions. These capabilities complement acquisition vation boreholes and in promethodologies currently being implemented in ducing wells. As a first step, the field to estimate reservoir properties away Saudi Aramco is conducting from the borehole. New EM and seismic sensors an onshore permanent seiswill be permanently deployed in wells for fluid mic installation with 1,000 front mapping to provide crucial data for reservoir shallow buried 4C receivers management and field development. n W E D N E S D A Y | O C T . 2 9 , 2 0 1 4 | E & P DA I LY N E W S

Geological Expression and Seismic Characterization of Shales in Mexico Interpretation project will acquire, process and interpret 3-D seismic data from the Limonaria and Galaxia areas. By Chris Cottam and Maribel Lopez, ffA

n October 2012, the Sener-ConacytHydrocarbons fund awarded $250 million of financing to Mexico’s Petroleum Institute (IMP) and Pemex in a project titled, “Assimilation and Technology Development in Design, Acquisition, Processing and Interpretation of 3-D Seismic Data with a Focus on Shale Oil and Gas Plays in Mexico.” The objective of this project is to assess the prospective shale oil and gas resources in Mexico and, through the application of technologies, define the optimal methods for characterizing and producing Mexican shale resources. The project encompasses the acquisition, processing and interpretation of 2,700 sq km (1,042 sq miles) of 3-D seismic data from the Limonaria and Galaxia areas, which will be used to study the Agua Nueva (in the Eagle Ford) and Pimienta shales in the Tampico-Misantla and Burgos basins, respectively. The information being acquired includes full-

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In the third step of the GeoTeric structural workflow, the project team tests the parameters for the fault expression workflow and begins work on the stratigraphic workflow with testing of frequency decomposition and RGB blending, an example of which is shown.

combined analysis of both geometrical and geomechanical attributes. The success of an unconventional play is dependent mainly on rock properties such as total organic carbon, fracture density, rock brittleness, thickness, porosity, mineralogy and geometrical dimension. Seismic data are used to predict several of these properties. The ffA-IMP study includes methodologies for optimal data conditioning; thin bed analysis and overall resource estimation; fault and fracture analysis; and developing an efficient workflow for obtaining measurements of azimuthal and stress anisotropy. GeoTeric’s powerful color-blending techniques enable the co-rendering of multiple attributes for investigation of possible lithology and fluid changes and to describe faults, fractures and reservoir heterogeneity in the shales. The study also will investiSee MEXICO continued on page 25

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Figure 1. Initital results from the first phase of GeoTeric’s analysis of the Limonaria area indicate that data conditioning has led to improved vertical resolution, better localization of events and increased signal-to-noise ratio. (Images courtesy of ffA)

azimuth, high-density and multicomponent seismic data. The objectives of the GeoTer ic interpretation project are twofold: Through the analysis of the seismic data, reduce the uncertainty in assessing the volumetrics in unconventional shale oil and gas fields—identification of the socalled sweet spots; and through the integration of geophysical, geochemical and geological data, better characterize the prospective resource. ffA’s consultants and IMP geoscientists are using ffA’s GeoTeric software to gain a clear understanding of the structure, stratigraphy and reservoir heterogeneity of these important shale formations leading to an enhanced interpretation of the prospective areas by focusing on the

The DipAzi Combined volume illustrates some of the major features in the Limonaria area. The chaotic patterns on the right of the image are being influenced by carbonate deposition whereas on the left, two north-south trending major faults can be clearly seen.

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Overcoming Technical Challenges in Shale Development High-resolution imagery and elevation models can aid in well pad planning. By Julie Parker, Spatial Energy

hale development introduces a new level of operational complexity with respect to field operations for oil and gas operators. Long lead times reduce flexibility in operations. Delays in executing on the ground negatively impact the drilling schedule and cost operators real money. Overcoming technical challenges in shale development by using high-resolution imagery and elevation models in operational workflows and planning for well pad locations and pipeline routing can increase operational efficiency and production while reducing operating costs and environmental impact. The specific operational objectives are reducing the timeline in planning spud and construction time, reducing the cost of design and construction and improving efficiency of personnel. Since complexity of field operations seems to be an industrywide issue, Spatial Energy engaged with

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Aerial high-resolution imagery and elevation data assist in well pad planning. (Image courtesy of Spatial Energy)

multiple operators to document where the use of upto-date high-resolution imagery and digital elevation models (DEMs) would have a significant impact on their field operations. Together, the companies dug

deep into their operational processes and were able to create a generalized workflow for locating a well pad and routing a new pipeline. Spatial Energy then worked with operators to understand the kind of costs involved with these activities and to identify where in the workflow imagery that DEMs would provide a benefit. The use of high-resolution imagery and elevation data proved a strong return when effectively used in the planning phase of field operations. Spatial Energy calculated and verified the cost savings that could be captured. Operational cost savings included: • One to 1.5 average surveyor trip savings per well/pad equaled $1,500 to $2,250; • One to 1.5 average surveyor trip savings per preliminary route equaled $1,500 to $3,000; and • $4,000 to $8,000 per pad construction costs savings. In an example with 300 wells planned, the company estimated pad site surveyor costs savings between $450,000 and $675,000, facilities surveyor cost savings between $450,000 and $900,000 and pad site construction savings between $1.2 million and $2.4 million. There were numerous benefits to drilling and facilities for the companies. On the drilling side, companies were able to increase efficiency by ensuring that drilling had all information necessary to pick preliminary locations from the office, making the decision faster and making better use of drilling and field personnel time. In addition, the number and duration of trips to the field were reduced, and the current success rate of 30% to 50% for determining usable locations on the ground increased to nearly 100%. Surface damages could be estimated from their desk and even quicker than before. They also mitigated risk by staying farther ahead of the drill schedule and avoiding the potential for idle rigs. Other benefits included the accurate estimation of the time and cost to construct surface locations based on topography, vegetation and surrounding infrastructure. Companies’ drilling schedules also gained flexibility, and they were able to prioritize with better planning. They determined a baseline for contractor cost comparison and auditing. They also significantly reduced the time from planned well to approval for construction. Facilities benefits included a reduction in the number of field visits needed to determine location of existing infrastructure. They also were able to determine preliminary/prestake routes faster with more confidence and a higher success rate from the desktop. Companies determined timing and level of effort to construct facilities ahead of wells and other activities (land, damages, contractor bidding, etc.) In addition, they were able to avoid undesirable post-construction surface damages negotiation by staying farther ahead of schedule and increased flexibility gained with a faster decision and planning process. n

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TTI Orthogonal WAZ Seismic Imaging Survey technique takes a look from another angle. Contributed by TGS

he clarity of structures below complex salt bodies has been of interest since the discovery of subsalt petroleum systems in the mid-1990s. Wideazimuth (WAZ) acquisition techniques increase illumination in these complex areas. But even normal WAZ techniques have illumination deficiencies if the salt model becomes too complex or, more specifically, if it is complex in the crossline direction. To adequately capture the crossline energy from complex structures, better offset sampling is needed in the orthogonal direction. TGS’ “orthogonal” WAZ, where an additional WAZ survey is acquired perpendicular to the original survey, uses the Freedom WAZ and orthogonal Patriot WAZ surveys. The increased accuracy of tilted transversely isotropic (TTI) model building along with the increased illumination gained through the acquisition of an orthogonal WAZ survey can increase the interpretability of and confidence in subsalt structures. The main driving force behind orthogonal WAZ acquisition is the improved illumination that is gained by having full offsets recorded in the orthogonal directions. The original survey was acquired with a four-source-boat by twostreamer-boat acquisition scenario. The general footprint for this acquisition was 8 km (5 miles) in the inline direction by 4 km (2.5 miles) in the crossline direction. The orthogonal survey was acquired in the same manner but rotated 90 degrees. On a rose diagram it can be seen that there is fairly good offset and azimuth coverage to about 45 degrees in either direction off of the acquisition orientation. The summation of these two surveys yields a fairly complete offset/azimuth distribution to about 8 km. One advantage to processing the orthogonal WAZ survey is that there is an existing WAZ survey from which TGS could obtain a starting velocity model. A smoothed version of the vertical transversely isotropic velocities was used to generate a vertical velocity model that subsequently calibrated with check shot information from wells in the area. The existing data volume was used to measure dip volumes with good fidelity above salt structures. The estimated dip field was then used to estimate the axes of symmetry (theta and phi, which is assumed to be perpendicular to the bedding). Migration was performed using the calibrated velocity model, and anisotropic parameters epsilon and delta were derived using an automated focusing analysis technique. The first step in this workflow is splitting the input data into six separate offset sectors for velocity refinement. Each sector maintained reasonable fold. Having too few offset sectors would not allow for optimum resolution of the velocity inhomogeneity. Each of these six sectors was then migrated, yielding six sets of common image point gathers, each with different residual curvature trends. All sectors ran through tomography separately, and merged attribute grids unified inversion should better solve to the velocity inhomogeneity by simultaneously backpropagating the errors along the respective input

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tions of salt modeling were carried out along with additional iterations of overhang and subsalt velocity updates. In addition to tomog raphic subsalt velocity updates, one final subsalt velocity update was carried out using a delayed imaging time RTM velocity scanning method. After the velocity modeling was complete, final migrations were run. Individual TTI RTMs for the Depth comparison between Freedom WAZ vs. orthogonal Patriot WAZ data is shown. (Image courtesy of TGS) original survey were run as well as for the orthogonal survey. Looking through the volume of data, there are many areas azimuths. Two iterations of multi-azimuth tomograbelow salt where one orientation is preferable to the phy were performed in refining the velocities. other. Structural complexity in one direction is forOne final sediment full-azimuth tomographic tunately often times found to be complemented by update was done at a finer increment found to be simpler structures in the perpendicular direction. In advantageous where updates and azimuthal variathese cases, the images oriented along simpler structions would be minimal. Salt modeling continued tures yield better illumination, which in turn yield from this point. At each stage of salt picking, TTI clearer sharper images. reverse time migration (RTM) volumes as well as Visit TGS at booth 825 for more information. n TTI Kirchhoff volumes were generated. Six itera-

Future SEG Meetings 2015 SEG Annual Meeting New Orleans, La. Oct. 18-23

2016 SEG Annual Meeting Dallas, Texas Oct. 16-21

2017 SEG Annual Meeting Houston, Texas Sept. 24-30

2018 SEG Annual Meeting Anaheim, Calif. Oct. 14-19

2019 SEG Annual Meeting San Antonio, Texas Sept. 15-20

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Unleash the Value of Seismic Assets The ability to locate and access data determines the value of the actual data. Contributed by Katalyst Data Management

he oil and gas industry has relied on seismic data to explore and exploit reserves for nearly a century. The types of data storage methods have changed almost as frequently as the methods used to acquire the actual data. For many years, seismic data were simply recorded on paper before the introduction of magnetic media. With magnetic media came reels and tapes of all sizes, which got smaller and smaller as the media became more advanced. Now the goal is to store everything digitally, although tapes are still widely used. That being said, what do geophysicists do when they need seismic data from the 1970s that’s hiding somewhere in storage? Even if the box of data can be physically located, the data are likely to be in a media type or format that has been outdated for decades. Getting the data in hand can take weeks or months. This is a common issue that many companies face. Since time is of the essence in this industry, being able to access data quickly is a valuable commodity. One solution is relying upon data management companies with the expertise in handling and managing seismic data. Katalyst Data Management has been providing solutions that address these issues for more than 30 years and employs domain experts who have the knowledge and experience to convert the most obscure formats used in the industry. The company’s extensive collection of legacy and modern tape drives provides it with the capability to recover irreplaceable data currently stored on legacy media as well as handle all new media types.

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Handling legacy media with care One serious problem that affects legacy magnetic media is a phenomenon commonly referred to as

Legacy tape drives transcribe data to modern digital media. (Image courtesy of Katalyst Data Management)

“stiction.” Stiction is a degradation of the binder that binds the metallic oxide to the polyethylene tape base. The cause of the degradation is a hydrolysis action resulting from exposure to humidity or moisture. The resulting deterioration causes the binder to become sticky and adhere to the backside of the tape and to the tape guides and heads. As the binder becomes sticky, the tape sticks to itself and to the tape drive tape path, and permanent er ror s will result. Katalyst has developed a process that temporarily reverses the stiction process and permits nearly 100% data recovery in most cases. From legacy to digital Maintaining the integrity of data is the goal when reading the seismic from tape or paper documents. The best way to achieve this is to capture the data from the original source. Many companies assume having a metadata

catalog of their data ensures that they know what data they have. Experience has proven that companies do not truly know what they have until all the data have been read and validated. Each component of the seismic collection is captured and attached to the correct navigation data so that it can easily be queried through an ESRI map interface. The data are quality-controlled to ensure that trace data are converted properly and all header information is fully populated. After all of that, the data reside in “virtual” electronic storage, and every time they are accessed an electronic version of those data is sent as requested. Subsurface data can be accessed using iGlass, a webbased ESRI GIS map interface built on the 3.8 public data model. Katalyst can offer the industry an end-to-end data management solution. Since Katalyst stores proprietary data for clients, several companies have opted to license their data online to make a return on their often considerable seismic investment. Last year Katalyst launched seismiczone.com, an online marketplace for marketing and licensing proprietary seismic data. For additional information, visit Katalyst at booth 916 or visit the company’s website at katalystdm.com. n

>> DOLOMITES continued from page 10 then be used to derive Pe from seismic data. Such a cross-plot is shown in Figure 1b, where one can notice a linear relationship in the scatter of points, which are color-coded with density. The dashed blue and magenta lines on this cross-plot show the effect of porosity for dolomite and limestone, respectively. For deriving these attributes from seismic data, the Arcis team began with the prestack seismic gathers. After generating angle gathers from the conditioned offset gathers, the P reflectivity and S reflectivity are derived using Fatti’s approximation to the Zoeppritz equations. Due to the band-limited nature of acquired seismic data, any attribute extracted from it also will be band-limited and so will have a limited resolution. As the target dolomite reservoir is thin, it is necessary to enhance the resolution of the seismic data. For this purpose, thin-bed reflectivity inversion was run on the two reflectivities and then filtered back to bandwidth that was higher than the input data bandwidth. These filtered thin-bed reflectivity data were next inverted into P impedance and S impedance. Once these impedance volumes are obtained it is possible to compute LI. Using the relationship between LI and Pe established from the well data, the team transformed the LI volume into a 3-D volume of Pe and used that to infer the dolomitic zones. To map the dolomite zones laterally, a horizon slice of Pe volume over a window that includes the zone of interest was generated. A part of that horizon slice is shown in Figure 1c, and a fairly good match was seen at the blind wells. It has been found that through the 3-D area the predicted Pe response within the reservoir interval correlates fairly well with the net to gross dolomite within the same interval. n

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HD Exploration with Broadband Seismic New generation of seismic acquisitions and processing techniques recover high level of structural and stratigraphic detail. By Duane Dopkin, Paradigm

wealth of new and greatly enhanced high-definition (HD) images are quickly coming online, ready for high-resolution interpretation, characterization and modeling. These HD images are coming from a new generation of broadband seismic acquisitions and broadband seismic processing techniques. Broadband seismic images are capable of recovering a level of structural and stratigraphic detail not present in images obtained from standard seismic acquisition and processing. Broadband seismic data are also the impetus for a new generation of quantitative seismic interpretation solutions that drive a more unified and concurrent approach to transforming seismic amplitude data to elastic and rock properties. Broadband seismic acquisitions are now routinely employed for offshore acquisitions and include slanted and variable depth streamers, over-under streamers, dual sensor streamers and others. These customized acquisitions remove source and receiver ghosts and can significantly enhance the resolution of seismic data with high added value coming from the recovery of low frequencies. These low frequencies can mitigate the nonuniqueness of seismic inversion methods and allow geoscientists to work with more confidence with inversion methods. Algorithmic processing approaches also have emerged for application to conventional towed streamers and ocean-bottom seismic acquisitions to correct the source and receiver ghost notches in the amplitude spectrum and recover low frequencies to improve seismic bandwidth and resolution. When implemented and applied properly, these technologies can bring significant added value to both legacy and modern seismic acquisitions. Paradigm has implemented a solution to recover the notches in the seismic spectrum introduced by the source and receiver ghosts generated at the water surface by estimating and applying a recursive deghosting filter. The problem is formulated as a nonlinear inversion process with a specific minimization criterion to estimate the source and receiver ghost times as well as the reflection coefficients at the air/water contact for both the source ghost and receiver ghost. The output is ghost-free seismic data suitable for processes like bandwidth extension and seismic inversion to produce high-resolution and HD seismic interpretation images. Paradigm has made this deghosting procedure available to the industry in its Echos seismic processing system with its recent Paradigm 14.1 software release. However, the solution does not end there. While broadband seismic images are capable of recovering a level of structural and stratigraphic detail not present in standard acquired and processed seismic images, recovering this detail is not straightforward with conventional interpretation and modeling systems. Time constraints coupled with less-than-optimized automated or computer-assisted picking methods often result in an under interpreted and under modeled dataset. Why should such r ich reflectivity datasets be generated if they cannot be practically interpreted and modeled? New procedures that move from surface-based to full volumetric interpretation and modeling solutions become essential to fully optimize the value of broadband seismic acquisition and processing. With these processes, geoscientists can address a number of limitations in the interpretation and modeling of reflector rich datasets. With new volumetric interpretation procedures, the interpreter has the freedom to add as many faults and interlayer reflectors to the interpretation dataset without loss of time and without compromises to the stratigraphic model.

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This coupling broadband seismic processing with depositional transformation augments the interpretation procedure, allowing unprecedented levels of stratigraphy and facies infor mation not easily secured with standard interpretation workflows to be added to the Images from before and after broadband deghosting are shown. (Image courtesy of Paradigm) interpretation and modeling scene. This new style of volumetr ic interpretation By constraining this rich interpretation dataset merges automated volumetric interpretation and with 3-D chrono-stratigraphic modeling, difficult chrono-stratig raphic modeling procedures to horizon correlations are simplified, and horizon secure a higher return on investment from the and fault integrity can be validated with geologic HD images generated by broadband seismic cr iter ia rather than subjective reasoning. acquisition and processing. It also allows the interFurthermore, additional stratigraphic features can pretation and modeling workflows to proportionbe extracted from broadband seismic images by ally incorporate the detail and resolution of data transforming the broadband data to chrono-stratirecovered from broadband methods without loss graphic space and carrying out the interpretation of interpretation time. n in this domain.

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Touring the Marvels of Denver Enjoy a complimentary tour at one of the many fascinating attractions the city has to offer. By Ariana Benavidez, Associate Editor, E&P

here is something to satisfy everyone’s interests in the entertaining city of Denver including many free tours in and around the city. Located in downtown, Great Divide Brewing Co. offers complimentary behind-the-scenes tours at 3 p.m. and 4 p.m. Monday through Friday and each hour from 2 p.m. to 7 p.m. on Saturday. Tours last about 30 minutes. Or after a long day at SEG, kick back and relax in the Tap Room, which features 16 taps of seasonal and year-round beers as well as views into the brewhouse. Tap Room hours are 12 p.m. to 8 p.m. Sunday through Tuesday and 12 p.m. to 10 p.m. Wednesday through Saturday. The venue hosts some of Denver’s most popular food trucks. Great Divide is the winner of 18 Great American Beer medals and the recipient of five World Beer Cup awards and was rated 12th in ratebeer.com’s 2013 list of “Best Brewers in the World.” It is located at 2201 Arapahoe St. For more information, visit greatdivide.com. Attending SEG all week? Be sure to save time for another one of the city’s most entertaining tours. The Hammond’s Candies factory offers visitors a chance to see how its candy is handmade and hand-packaged from beginning to end. It’s a must-see attraction for candy lovers of all ages. The company, located at 5735 N. Washington St., has been making candy in Denver since 1920. The free 30-minute tours run every half hour from 9 a.m. to 3 p.m. Monday through Friday and 10 a.m. to 3 p.m. on Saturdays. The factory is closed on Sundays. Candy fanatics also can enjoy free samples after the tour or indulge themselves by purchasing their favorite treats from the Hammond’s

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Candies store. In 2011, the company entered into the gourmet food world with the launch of its dessert dips and snack pretzels. So there is definitely something for all variations of a sweet tooth here. The comDenver is home to one of only two pany receives more mints in the U.S., producing nearly 50 million coins a day. (Image courtesy of than 100,000 visitors a year.Therefore, reserStan Obert and VISIT DENVER) vations are required for groups of 10 or more. Check out hammondscandies.com for more information. Another noteworthy stop for tourists is the Denver U.S. Mint, which is one of only two mints in the U.S. Here, visitors can learn how coins are produced and the history of coinage as well as get an up-close look at the coins as they come off the production lines in this 45-minute tour. Tours are from 8 a.m. to 3:30 p.m. Monday through Thursday, and the mint is located at 320 West Colfax Ave. Please note that purses, handbags and backpacks are prohibited on the tours. To make a reservation, go to usmint.gov/mint_tours. Denver offers a vast number of tour options. However, there is even more to explore in the surrounding areas. Colorado Springs is home to the 35-acre U.S. Olympic Training Center, where nearly 140,000 visitors a year enjoy the 45-minute walking tour of the athlete training facilities, aquatic center, weight-lifting space and more. It’s the flagship training center for the U.S. Olympic Committee and the Olympic Training Center pro-

The chapel on campus at the Air Force Academy in Colorado Springs, Colo., is the most popular manmade attraction in Colorado. (Image courtesy of Rich Grant and VISIT DENVER)

grams. Tours are scheduled every hour from 9 a.m. to 4 p.m. Monday through Saturday at 1 Olympic Plaza. Admission is $5. For more information, visit teamusa.org/About-the-USOC/Training-Centers-andSites/Colorado-Springs. Another interesting stop in Colorado Springs is the U.S. Air Force Academy. Explore the 2,936-sqm (31,600-sq-ft) visitor center, walk the nature trail at the foot of Pikes Peak or visit the Cadet Chapel. The visitor center features a 525-sq-m (5,652-sq-ft) exhibit area, a snack bar and a gift shop. In fact, if visitors come at noon on Monday, Wednesday or Friday, they can catch the cadets marching to lunch—a fun sight to see. Tour maps and information on the academy are available at the information desk. For additional information, call the visitor center at 719-333-2025, which is open from 9 a.m. to 5 p.m. n

Redefining Resolution Ultrahigh-resolution 3-D seismic imaging can accurately identify and delineate structurally complex geohazards. crossline dip will be incorrectly located and imaged. Accurately identifying and delineating these structurally complex he E&P industry has long recognized geohazards is the province of ultrahighthat the responsible development of resolution 3-D (UHR3D) seismic imagoffshore hydrocarbon resources demands ing. The advantage of UHR3D over other an in-depth understanding of the risks types of analogue and digital site-survey associated with shallow geohazards. These data used to detect geohazards is that hazards include seabed and shallow subUHR3D comprehends the 3-D nature of surface geologic features such as shallow both the seismic wavefield and the geogas and shallow-water flows, slumps and logic features of interest, thereby enabling scours, shallow faulting and glide planes, the accurate imaging of these features in shallow buried channels, mud volcanoes, their true subsurface locations. gas hydrates and mounds, incompetent As an example of this type of dataset, a sediments and overpressured zones. consortium consisting of NCS SubSea, Geotrace and Spec Partners recently conducted a regional UHR3D survey in the central Gulf of Mexico. This survey, known as SAFE-BAND, was acquired using P-Cable technology, which supported a receiver spread comprised of 18-m-long by 100-m-long (59-ft-long by Figure 1. This profile illustrates the exquisite illumination of faulting and small shallow gas anomalies (scale presented assuming a velocity of 1,600 328-ft-long) streamers spaced 12.5 m (41 ft) apart. The receiver m/sec). (Images courtesy of NCS SubSea) group interval for each streamer was 6.25 m (20.5 ft), and a single 210-cu.Given the critical nature of geohazard in. generator-injector (GI) gun energy detection and delineation for offshore source was fired every 12.5 m. This surdrilling and infrastructure integrity, the face geometry resulted in a fourfold legacy practice of using ultrahigh-resoludataset with spatial bin dimensions of tion 2-D seismic images is clearly inadequate and potentially dangerous since any seafloor or subsurface features with See RESOLUTION continued on page 26 >> Contributed by NCS SubSea

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>> ROAD continued from page 1 logical and reservoir objectives. In addition, better risk reduction tools such as realistic acquisition modeling and the ability to better understand noise can benefit from the technique. Sergey Fomel of the Jackson School of Geosciences at the University of Texas at Austin looked at the importance of time migration in seismic operations and debunked several myths about the technique. First, he found that time migration doesn’t require travel times. Travel times might be needed to define time migration, but they are not needed to implement time migration. The second myth he examined regards time migration needing velocity analysis, which is false. Velocities in time migration can be replaced with local slopes measured from the data, he explained. For the third myth, when looking at whether velocity analysis needs prestack data, he found that time migration velocity can be estimated from single-offset data by measuring the focus of seismic diffractions, proving the myth false. The fourth myth questioned whether time mig ration needs approximations, which was proved false. Approximations involved in time migration can be increasingly more accurate, he said. No approximation is necessar y if timedomain imaging is implemented via wave equation time migration. Last, he found the belief that time migration can distort images to be true. “In the case of lateral velocity variations, time migration images are

distorted,” he said. Distortions, though, can be removed by time to depth conversion using regularized inversion. Dur ing the presentation, “Making the most out of the least: squares migration,” Gerard Schuster of KAUST looked at the least squares migration technique as compared to standard migration methods. Sergey Fomel The least squares migration technique was first used by Lailly in 1983 and Tarantola in 1984, and it was known as linearized inversion at the time. Since its introduction, the method has been shown to be a viable solution to the migration problems of defocusing and aliasing and also can provide better resolution. Least squares migration does come with its challenges, too. The technique often shows high sensitivity to inaccurate velocity. This can be overcome through statics corrections. Another challenge of the method involves the high cost. The solution, Schuster explained, is to migrate blended supergathers. This results in one reverse time migration (RTM) to migrate many shot gathers, as compared to standard migration, which results in one RTM per only one shot gather. “With blended methods, the cost [of least squares migra-

tion] can be almost the same cost as standard migration,” Schuster said. BP’s John Etgen examined how adaptive optics, a technology used in astronomical telescopes, can be applied to the seismic industry. In complex overburden, velocity is the main problem. Even small interpolation errors made in imaging can become major issues. Adaptive optics, Etgen said, can become the pathway to improved images. Velocity model accuracy is the prime limitation to image quality below complex overburden. Full-waveform inversion (FWI) and image gather analysis may not ride to the rescue entirely. FWI looks at the problem in the space of the data. “The problem [that] is there isn’t really a clear signature of what’s wrong in the data themselves,” Etgen said. Adaptive optics uses an adaptable lens to analyze the wavefront, and geophysicists can look for shortperiod errors. The lens can then be reshaped to remove those errors, resulting in an improved image. Using an adaptive optics algorithm the technology can be applied to the seismic space to see waves in real time and analyze where they have trouble, which can be highly diagnostic. By looking at how this type of technology could be applied to geophysics, Etgen hoped to get others thinking about “another way of looking at wavefields that offers some insight.” n

>> MEXICO continued from page 19 gate techniques that allow seismic facies classification via real-time interaction with a multidimensional attribute space. Following the investigation, optimal workflows for each of the Limonar ia and Galaxia areas will be designed, creating a set of default parameters and workflow guidelines for future analyses. At press time, the analysis of the first tranche of about 400 sq km (154 sq miles) of high-quality prestack time-migrated data from Limonaria had started. The first step in the GeoTeric workflow is to apply data conditioning, which has two aspects. First, advanced noise cancelation algorithms are used to attenuate both random and coherent noise while maintaining subtle amplitude variations, edges and discontinuities within the seismic data. Second, the spectral enhancement workflow is applied to increase the bandwidth of the data by balancing the contribution of different frequency bands within the dataset. Initial results shown in Figure 1 indicate that data conditioning has led to improved vertical resolution, better localization of events and increased signal-to-noise ratio. The impact of this is faster, higher confidence horizon interpretation, easier fault interpretation, more reliable attribute analysis, clearer visibility of subtle features and a significantly improved image for all subsequent workflows. These factors were particularly important for shale plays where thin bed analysis and the detection of small-scale faults are critical interpretation objectives. Following data conditioning, the initial step in the structural workflow is designed to create a detailed understanding of the structural setting throughout the area at all stratigraphic intervals. The DipAzi Combined volume in Figure 2 illustrates some of the major features in the area. The chaotic patterns on the right of the image are being influenced by carbonate deposition, whereas on the left two north-south trending major faults can be clearly seen. In the next step of the structural workflow, the project team is testing the parameters for the fault expression workflow and is starting work on the stratigraphic workflow, with testing of frequency decomposition and RGB blending, an example of which is shown in Figure 3. The GeoTeric project is expected to run throughout 2015 with final results being delivered in firstquarter 2016. n E & P DA I LY N E W S | O C T . 2 9 , 2 0 1 4 | W E D N E S D A Y

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Cross-Correlation and Subspace Detection Methods Do More with Less Advanced tools for induced seismic monitoring can detect more events at lower thresholds. Contributed by Nanometrics

aveform cross-correlation and subspace detection are advanced tools for induced seismic monitoring that can detect more events at lower thresholds over greater distances. The result is a more complete catalogue that might shed light on induced seismicity precursors and insight into mitigating larger induced seismic events. The Crooked Lake earthquake sequence that occurred between Nov. 29, 2013, and Dec. 13, 2013, near Fox Creek, Alberta, Canada, is recognized as an induced seismic cluster and was the focus of a recent study by Nanometrics on cross-correlation and subspace detection. Twenty-four events were detected during the time period via short-term averaging (STA)/long-term averaging (LTA) triggering at stations across northeastern British Columbia and western Alberta. The goal in applying the correlation and subspace detection method to the event swarm was to identify additional events not previously detected by the STA/LTA trigger. To this end, the largest event—a magnitude 3.9—was used as a template event, and a waveform cross-correlation was performed to iden-

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tify events not detected by the STA/LTA trigger. The events ranged from magnitude 2.5 to magnitude 3.9. The 24 originally detected events and the template event are shown in Figure 1. Over the course of the 15-day cluster, the crosscorrelation detection method located five times as many events and reduced the detection threshold by about 0.8 magnitude units. The cross-correlation detector identified 113 locatable events, including all 24 events detected by the STA/LTA trigger. These findings support previous studies on cross-correlation detection algor ithms (e.g. Gibbons and Ringdal, 2006). The success of the cross-correlation technique in this study also highlights what can be achieved with a relatively sparse network. Though the closest stations were more than 200 km (124 miles) away, the network was still able to reliably detect and locate events of magnitude 2 and greater. If the events of interest in a region all occur in a few highly localized regions and through similar fault mechanisms, then cross-correlation and subspace detection offer an effective way to harvest a rich catalogue with a sparse seismic network, provided that a satisfactory template has been recorded.

>> RESOLUTION continued from page 24 3.125 m (10.3 ft) by 6.25 m. The temporal sampling interval selected for the survey was ¼ ms (2,000 Hz aliasing frequency), which was subsequently subsampled to ½ ms during data processing. Although processing of this dataset is still underway, preliminary time migrated results (Figure 1) show an astonishing level of detail and clarity in imaging the shallow subsurface geology. Of particular interest are the shallow faulting, shallow gas and gas hydrate features, and mass transport deposits. The fine detail that UHR3D is able to image in this complex geologic setting is particularly impressive given the limited offset range of the recorded data, which can lead to illumination issues for steeply dipping events. This offset limitation precludes the measurement of seismic velocities from the recorded data, and as a result, stacking and migration velocities must be obtained from an external source—in this case a velocity model developed by Geotrace using check shot data. The quality of the imaging results obtained using this velocity model validates the soundness of this approach and the suitability of this type of velocity data for ultrahigh-resolution imaging applications.

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Figure 2. A near seafloor pick (first zero—negative to positive) illustrates the complexity of the seafloor geomorphology.

It is also encouraging to observe that despite the use of a modest energy source (a single GI airgun) NCS was able to clearly image events more than 2 seconds below the seafloor. The depth of penetration means that this ultrahigh-resolution technique can be used for shallow resource exploration as well as geohazard imaging. Given the level of detail captured by this method, there also is the potential to use the technique for time-lapse monitoring.

Figure 1. Events detected by the STA/LTA detection algorithm between Nov. 29, 2013 and Dec. 13, 2013, are shown. (Image courtesy of Nanometrics)

Visit Nanometrics at booth 150 for more information. To obtain a copy of the Crooked Lake sequence study, go to nanometrics.ca/microseismic/technical-resources. n

In addition to unparalleled shallow subsurface imaging, NCS was pleased to confirm that the water bottom arrival data using P-Cable technology provided detailed bathymetric information that rivals that of ship-mounted multibeam sonar (Figure 2). When combined with shallow subsurface details, the seafloor morphology revealed by these images helps to provide a more complete understanding of the geologic processes involved in shaping these features. Perhaps most exciting is the fact that the economics of this technique, when applied over relatively large areas, are not vastly different from those of the legacy 2-D methods it is designed to replace. The SAFE-BAND partnership has leveraged these economics by developing a large-scale regional survey program designed to identify regional geohazard and shallow exploration trends as well as detailed images with sufficient resolution for drilling and infrastructure planning. This combination of a largescale survey and ultrahigh-resolution imaging provides the interpreter with the best of both worlds: extremely accurate and detailed subsurface images within the context of a larger regional framework that provide the geologic setting within which the imaged features have developed. n

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>> ERA continued from page 1 uate and consider solutions and strategies,” according to geologist Bob Raynolds. Raynolds will be presenting “Flourishing in the Anthropocene: The Science Challenges” at this years’s SEG Applied Science Education Program, a free event geared toward high school students. The hourlong science program is meant to inform students about society’s transition toward sustainability and the issues associated with changing the influx of information into knowledge as well as engaging them to pursue a career in the geology field. “Some of the people in the audience will be the scientists of tomorrow,” Raynolds said in an interview with E&P. Raynolds is currently a consulting geologist, a research associate at the Denver Museum of Nature and Science and an adjunct professor at the Colorado School of Mines. He has worked at companies such as Exxon and Amoco as an exploration geologist. He also has taught at Dartmouth College, where he received his Ph.D., as well as in Pakistan for a year at Peshawar University. In defining the term Anthropocene, Raynolds explained that geologists subdivide time according to life activities and the kinds of animals, plants and other living things that have cohabitated on earth. The population curves, impact of people on landscapes, energy use and a wide variety of measures of consumption and processing are all studied by geologists, he said. The Anthropocene is the current geological time period that many scientists believe we are now in. It is defined as being human-influenced based on global evidence that atmospheric, geologic, hydrologic, biospheric and other earth system processes now are altered by humans, according to The Encyclopedia of Earth. “We often think of the present as being the key to the past,” he said. “Now we’re recognizing that the past is the key to the present. We’ve turned the paradigm on its head, and we’re looking now at episodes in the geological record or in the past to try to better inform ourselves about what’s going on today.” As the planet warms up, changes in ecosystems are expected as well as changes in habitats, precipitation patterns and agriculture, according to Raynolds. There will be mass migration, people moving across the nations and “tremendous disruptions of existing social structures,” he said. “We’re going to see a wide variety of cultural and social manifestations that are only dimly appreciated right now, and it’s going to affect the lifetimes of these young people dramatically.” Due to the challenges the planet faces, there need to be major modifications to the way humans live. Raynolds suggested a few areas that will need to meet those changes, including modifying the conditions of coastal communities and the way in which water is used for irrigation. “There are tremendous challenges and opportunities [in the geosciences field],” Raynolds said. “There’s going to be a lot of careers made in trying to better understand how to cope with what’s going on around us.” In focusing on his upcoming Applied Science presentation, Raynolds said the science challenges he’ll discuss involve getting better data. Students will need to look at ways to cope, mitigate, adapt or become resilient to both the anticipated and ongoing changes, he said. “I would hope that the students would feel engaged in data acquisition [and] that they would be interested in looking at modifications of these ecosystems that [are] a function of changing climate.” One example Raynolds gave was the diminishing supply of water in Colorado. Whether the students are aware or not, this is a serious problem in their very own community and something that will become a part of their consciousness sooner or later. Half of the water in Denver comes from the Colorado River, which is diminishing year by year, and this is

Bob Raynolds recharges a Denver Basin aquifer using his morning coffee. (Image courtesy of Bob Raynolds)

going to cause major issues among the cities that use the same water (Las Vegas, San Diego, Tucson and Phoenix), he said. In trying to accommodate these challenges, there is a great deal of engineering and reallocation of energy in terms of how to use resources that exist today, Raynolds said. The goal is to do things more efficiently—for instance, using less water in agriculture practices, domestic use and landscaping. “There are tremendous changes going on in the energy industry right now as we abandon coal and switch to natural gas, and as we

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go forward there will be a move away from the carbon-based electricity generation in the world, not just North America. There will be a tremendous change in the way we use carbon-based fuels,” he said. Students and attendees will find that their careers are or will be shaped by this phenomenon, he continued. To a large extent, the scientific training and skillsets that students gain in high school and college will be called upon to help find, design and create solutions to these challenges. His advice to students is that with the pathway right in front of them, they need to pay attention and apply themselves. “These people who will be in the room [at the Applied Science Education Program] are the people who will be solving the problems that we can see coming in the pipeline today,” he said. “Science [is] always changing, and it constantly challenges us to get more information. We always need more information, and we need lots of people looking at it. We need young, enthusiastic people who are going to be willing to roll up their sleeves and tackle the problems that are coming their way.” The science program is scheduled for 10 a.m. Wednesday, Oct. 29. High school students and teachers can register by contacting the SEG business office via email at [email protected] or by phone at 918-497-5525. The program is free for annual meeting delegates and does not require registration. n

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