DISTINGUISHED LECTURERS

Creating a Worldwide Unconventional Revolution Through a Technically Driven Strategy

Unconventional development propelled the United States to produce more oil than it imports for the first time in 20 years, and the increased production of oil and gas profoundly affect-ed US economic growth and job creation. During this evolu-tion, there was a need to address environmental regulations and infrastructure requirements to access the sheer volume of resources. Based on today’s horizontal drilling and hydraulic fracturing technology, a strategic development plan can be con-structed for any country to create an unconventional energy opportunity. In this lecture, the experience from US develop-ment is used to provide a fully integrated workflow for develop-ing shale oil and gas reservoirs.

Basak Kurtoglu is vice president in the global energy group at Citigroup Investment Bank. Previously, she was integrated project team manager at Marathon Oil. Kurtoglu earned her BS degree from Middle East Technical University and her MS and PhD degrees in petroleum engineering from Col-

orado School of Mines.

Lessons Learned, How NOT To Do Drilling Automation

The uses of automation in drilling are expanding and typically resulting in improved performance. However, many of these projects struggle in the initial stages, often trying to overcome a common set of hurdles. Many of these hurdles are not tech-nical challenges, but involve people issues and the implemen-tation methods. This presentation covers the basics of drilling automation and describes the problems and solutions that have been found to improve the startup success for drilling automa-tion. The idea to take away: For automation to be successful, the key users, especially the driller, must be involved in every step of design and implementation.

Bill Koederitz is chief technology officer at GK Plus Innovations. Previously, Koederitz spent 20 years building real-time applica-tions and drilling automation systems at National Oilwell Varco. Koederitz holds BS, MS, and PhD degrees in petroleum engi-neering from Louisiana State University and

is a registered petroleum engineer in Texas. He has authored or coauthored 25 technical papers and holds 15 patents.

Evaluating Completion Options To Maximize Value

The completion engineer integrates the requirements of a num-ber of disciplines (such as reservoirs, drilling, and production) to maximize the value of a hydrocarbon resource. This almost always requires evaluating competing and conflicting factors to determine the “best” option for a particular problem. This talk will demonstrate a decision-making process that allows the stakeholders to compare options in a fair and robust way. Two real onshore or offshore examples will be reviewed, depending on the SPE chapter’s interest. Members will take away a new methodology for comparing competing factors that influence a completion or well design.

Dan Gibson is a senior completions and well integrity engineer with more than 35 years’ experience. He has worked his way through the oil and gas production stream from facilities and production engineering to completions in assignments across the United States and around the world. Gibson

has authored or coauthored papers ranging from topics of poly-mer flood management to ice mechanics and most recently an innovative inflow-control device.

Topics Set for 2016–2017Distinguished Lecturer SeasonWith speakers from a variety of disciplines and professions, the program focuses on industry trends, challenges, and technology applications. The following speakers and topics will be presented.

Operational Geochemistry at Work: Integrate or Perish!

Fluid properties have a profound impact on exploration and production (E&P). Yet many projects go through decision gates with a general lack of appreciation or awareness of the intrica-cies and interdependencies within the petroleum system. Oper-ational geochemistry is uniquely positioned to bridge the gap between the various subsurface and surface disciplines to make certain that reliable, complete, and consistent datasets are obtained and integrated, with quality assured, from the start of exploration and appraisal campaigns. A number of case studies will be presented that illustrate the workflow and describe the prize and the potential lost opportunities.

Daniel McKinney is Shell’s subject matter expert (SME) for operations geochemistry and was a founding member of the com-pany’s fluid evaluation and sampling tech-nologies team. He provides geochemistry and formation testing solutions for Shell in his current position in Malaysia, having held

a number of previous posts in the United States during his 17 years with the company. He holds a BS degree in chemistry and a PhD in material science and engineering, both from Penn-sylvania State University.

The Value and the Danger of Complex Reservoir Simulations

The weakness of reservoir simulations is the lack of quantity and quality of the required input. Their strength is the ability to vary one parameter at a time. Thus, simulations are an appro-priate tool to evaluate relative uncertainty, but absolute fore-casts can be misleading and may result in poor business deci-sions. As recovery processes become more complex, the impact of such decisions may have a major impact on project viabil-ity. A responsible use of reservoir simulations is discussed for technical users and decision makers, and examples of the value and danger of these complex simulations are shown. This is a call for the return of the reservoir engineer who is in control of the simulations and not controlled by them, and the decision maker who appreciates a black-and-white graph of a forecast, with realistic uncertainties, more than a 3D hologram in color.

Daniel Yang is petroleum advisor at Shell Canada. He holds a PhD in geophysics from the Technical University of Berlin, Germany. Yang has dedicated 15 years of his oil- industry career to enhanced oil recovery (EOR) methods, with a focus on thermal recovery that originated from 10 years of

geothermal energy research. He has worked at Shell Interna-tional, Canadian Natural Resources, and Laricina Energy. Yang

holds two patents, was recognized as a Shell SME, has more than 20 publications, received an SPE Best Paper Award, and was a guest lecturer at universities in Germany, the United States, and Canada.

Incorporating Numerical Simulation Into Your Reserves Estimation Process: A Practical Perspective

Reservoir simulation is a sophisticated technique for forecast-ing future recoverable volumes and production rates that is becoming commonplace in the management and development of oil and gas reservoirs. Calculation and estimation of reserves continues to be necessary for assessing the value and managing the development of producer assets. While generally done for different purposes, these analytical methods require the knowl-edge and expertise of the analyst (typically a reservoir engineer) to arrive at meaningful, reliable results. Increasingly, the sim-ulation tool has been incorporated into the reserves process. However, precautions must be taken when relying on reser-voir simulation to estimate reserves. This discussion highlights some important facets to consider when applying numerical simulation methods to estimate reserves or augment estimates. The main take-away will be an appreciation for the needed focus areas for arriving at meaningful, defendable reserves esti-mates based on reservoir models.

Dean C. Rietz is president and member of the board of directors at Ryder Scott Petro-leum Consultants. He has more than 30 years of diverse experience in evaluating oil and gas properties, including more than 25 years of applying numerical modeling approaches to these evaluations. Previously, Rietz man-

aged the Ryder Scott Reservoir Simulation Group for approxi-mately 15 years and worked for Chevron, Gruy, and Intera before joining Ryder Scott. He received a BS degree in petroleum engi-neering from the University of Oklahoma and an MS degree in petroleum engineering from the University of Houston.

Verifying Performance and Capability of New Technology for Surface and Subsurface Facilities

As seen in the United States shale oil revolution, the develop-ment of new technology is an enabler in reducing capital costs, simplifying production, increasing the capacity of facilities, and, in some cases, making marginal projects profitable. While deal-ing with significant risk, the challenge of progressing technology can be overcome through technology qualification. A technolo-gy qualification program (TQP) provides a means of identifying risks and taking the correct steps to mitigate rather than avoid them. This lecture summarizes the required steps in qualifying technology and how to keep track of technology development through the technology readiness level ranking system.

Ed Grave is upstream senior technical advi-sor for fractionation and separation at Exxon Mobil Upstream Research Company in Spring, Texas. Recognized in the com-pany for his expertise in advancing new technology, he led ExxonMobil’s effort to design and qualify a separation system for

ultradeepwater. Grave initiated and is the technical chairman of the joint industry Separations Technology Research Program on qualifying separation equipment. He also served as vice chair of SPE’s Separation Technology Technical Section. Grave graduated from New Jersey Institute of Technology with an MS degree in 1982.

Energy Policy: Is it Effective? Is it Fair?

Developing sound energy policies is difficult at best, with a deli-cate balance required between government’s need for revenue, society’s need for energy, and the producer’s need for profit-ability to exploit resources. Good policies require an apprecia-tion for the interactions among oilfield development and opera-tions, costs and prices, taxes and regulations, and many other factors that are often difficult to define. The world is complex and acts like a system with many interconnected components, and there are no easy solutions in complex systems. Therefore, we developed an approach that uses system models and regret analysis to find flexible, resilient tax policies that would provide all parties with fair, profitable solutions, despite uncertainties and the fact that no party would achieve its maximum goals. Our approach also measures the relative benefits of existing energy policies and can potentially improve them.

Frank Blaskovich is vice president of Blas-kovich Services in northern California. He received his BS degree in aerospace engi-neering from the University of Notre Dame. Blaskovich has more than 40 years of expe-rience in reservoir engineering and simula-tion, software development, environmental

modeling, and policy analysis. He has worked on energy issues globally for the largest energy companies, government agen-cies, and consultants.

The Digital Oilfield—Collaborative Working at Global Scale

Collaborative working helps companies to operate assets more efficiently and to do so as one team, with the results of higher production; less cost; lower health, safety, and environmental risk exposure; and higher morale. Shell has pursued the Digital Oilfield for the last 10 years, under the heading of Smart Fields. Collaborative work environments (CWEs) were implemented in the majority of assets, now covering more than 50% of Shell’s production. The presentation will provide an overview of cur-

rent CWEs, give examples in different types of assets, and show the business value achieved. It will also show the structured deployment program and the standard design, implementa-tion, and embedding approach that was followed.

Frans van den Berg works in the global Smart Fields program in Shell’s Projects and Technology organization in the Nether-lands. He leads the company’s global imple-mentation of CWEs. Van den Berg has served in petroleum engineering positions, asset development leadership posts in opera-

tions, and global technology deployment roles. Since 2008, van den Berg has helped to organize the SPE Intelligent Energy and Digital Energy conferences. He joined Shell after graduating in physics at Leiden University in the Netherlands.

Performance Drilling Expectations, Perceptions, and Path Forward—Turning Challenges into Opportunities

Drilling activities continue to extend into harsher, more chal-lenging environments. In addition, directional drilling, with its increased activity level, has become more complex. As a result of these factors, operational costs have escalated. Performance drilling is universally accepted as an enabler in reducing opera-tional costs through improvements in drilling efficiency. How-ever, achievement of these expectations continues to fall short, and there is also most often a lack of consistency in the way that operators approach performance drilling. These conditions are primarily because of the industry’s different positions on what constitutes performance drilling. In most situations, the use of new technology, sophisticated tools, or expensive drive systems is classified as performance drilling. Primarily, this lecture will challenge and move away from such views. Most importantly, it will present new definitions, concepts, and processes that facil-itate consistent achievement of performance drilling’s objec-tives and benefits. In addition to establishing how performance drilling should be executed, a new benchmarking process that focuses on how and why events occur will be discussed.

Graham Mensa-Wilmot is a senior advisor drilling engineer in Chevron Energy Tech-nology Company. He is the company’s Max-Drill (performance drilling) project leader and a recognized industry leader in perfor-mance drilling. Mensa-Wilmot has more than 28 years’ experience in drilling applica-

tions research, downhole tool development, drilling vibrations identification and remediation, drilling mechanics, drilling sys-tem design and analysis, and drilling performance improve-ment. He holds 34 patents on the same disciplines and has authored 42 technical papers. Mensa-Wilmot holds an MS degree in drilling engineering from Romania’s Oil and Gas Uni-versity of Ploieşti.

The Role of Natural Fractures in Shale Gas Production: What Does Production Data Tell Us?

Natural fractures are very common in shale gas plays. It is often presumed that because the formations are so tight, gas can be produced economically only when extensive networks of natu-ral fractures exist. The creation of large fracture surface area in contact with the reservoir is considered essential to com-mercial success. This is facilitated by multistage hydraulic fracturing of long horizontal wells using large volumes of low- viscosity (low-cost) fracturing fluid. However, the efficiency of this process in terms of water usage is now coming under close scrutiny. The success of these operations is beyond doubt, but what can be inferred about the accuracy of this conceptual pic-ture in light of many years’ accumulated production data? What does production data tell us about the role of natural fractures? This presentation addresses these issues by using a semiana-lytic shale gas production model to analyze and interpret pro-duction data from many shale gas wells across several differ-ent plays.

Ian Walton is a senior research scientist at the Energy & Geoscience Institute of the Uni-versity of Utah and an adjunct professor in the department of chemical engineering. He holds a PhD in applied mathematics from the University of Manchester. Walton has more than 25 years of petroleum industry experi-

ence, most recently as a scientific advisor for Schlumberger, and more than 15 years of university teaching experience.

Improving Reservoir Simulation Modeling with Seismic Attributes

Seismic attributes are increasingly used in reservoir character-ization and interpretation processes. New software and com-puter capabilities enable the generation of large numbers of surface and volume attributes. These have proved very useful for the facies and reservoir properties distributions in geologi-cal models, which has improved their quality in the areas lying between wells and beyond wells. The seismic attributes can help geoscientists better understand the stratigraphic and structur-al features, the sedimentation processes, lithology variations, and other aspects. As a result, the estimation of the recoverable hydrocarbon volumes becomes more reliable and development strategies will become more successful.

Isabela Falk is a senior geologist and sub-surface team leader in a Schlumberger pro-duction and asset management project in Romania. Previously she worked as a project geoscientist for Fugro-Jason in Germany and the Netherlands and as a research geol-ogist for Romgaz, the Romanian national

gas company. In her 20 years in the industry, Falk has special-ized in geological modeling and become experienced in seismic inversion. She holds a PhD in geology from Babeş-Bolyai Uni-versity in Cluj-Napoca, Romania.

“Fooled by Randomness”—Improving Decision Making With Limited Data

Professionals routinely face the challenge of making informed decisions with limited data sets. Our exploitation of uncon-ventional resource plays has exacerbated the problem. We commonly refer to these resource plays as “statistical plays,” as large programs have provided repeatable year-over-year results. Decision making that relies on limited data sets has been driven by competitive pressures and the desire to get to the right answer as soon as possible. Development decisions are often made without due consideration of how representative the data are. Similarly, we frequently test new technologies with limited samples, expecting that a simple arithmetic comparison of the average results can validate or refute their further appli-cation. This talk presents the theory and use of aggregation curves as a pragmatic, graphical approach to determining the uncertainty in the sampled mean relative to the desired average program outcome.

James Gouveia, a partner in Rose & Associ-ates, is a professional engineer with a diverse technical, business, and operations back-ground. He has worked in a variety of techni-cal and managerial assignments in explora-tion, reservoir engineering, strategic and business process planning, and portfolio and

risk management. Gouveia served as an assurance champion and asset manager for BP and previously as director of risk manage-ment at Amoco Energy Group of North America.

Does Heavy Oil Recovery Need Steam?

Heavy oil recovery traditionally starts with depletion drive and (natural) waterdrive, with the result of very low recoveries. As an EOR technique, steam injection has become mature since the 1950s with the use of cyclic steam stimulation, steam drive or steamflooding, and steam-assisted gravity drainage. The high energy cost of heating the oil-bearing formation to steam tem-perature and the associated high CO2 footprint make steam-based technology less attractive, and many companies have actively sought alternatives or improvements. As a result, there are now many more energy efficient recovery technologies that can unlock heavy oil resources, compared with a decade ago. This presentation will discuss breakthrough alternatives to steam-based recovery as well as incremental improvement options to steam injection techniques. The key message is the importance to consider these techniques because of the cost and high CO2 footprint of steam injection.

Johan van Dorp holds an MSc in experi-mental physics from Utrecht University and joined Shell in 1981. He has served on sev-eral international assignments, mainly in petroleum and reservoir engineering roles. Recently, van Dorp led the extraheavy-oil research team at the Shell Technology Cen-

ter in Calgary, focusing on improved in-situ heavy-oil recovery technologies. Currently, he is senior consultant in the Neder-landse Aardolie Maatschappij, a Shell-operated joint venture, and serves as Shell Group principal technical expert in thermal EOR.

Automation of the Drilling System: What Has Been Done, What Is Being Done, and Why It Is Important

Drilling systems automation is the real-time reliance on digi-tal technology in creating a wellbore. It encompasses down-hole tools and systems, surface drilling equipment, remote monitoring, and the use of models and simulations while drill-ing. While its scope is large, its potential benefits are impres-sive, among them: Fewer workers exposed to rig-floor haz-ards, the ability to realize repeatable performance drilling, and lower drilling risk. While drilling systems automation includes new drilling technology, it is most importantly a col-laborative infrastructure for performance drilling. In 2008, a small group of engineers and scientists attending an SPE con-ference noted that automation was becoming a key topic in drilling and they formed a technical section to investigate it further. Among the answers are an open collaborative digital environment at the wellsite, an openness of mind to digital technologies, and modified or new business practices. What are the barriers? The primary barrier is a lack of understand-ing and a fear of automation. Digital technologies are trans-forming the infrastructure of the drilling industry. Drilling systems automation uses this infrastructure to deliver safety and performance, and address cost.

John Macpherson is a senior technical advisor for Baker Hughes. He holds a BSc (Hons) in geology from the University of Glasgow. During Macpherson’s 40 years in the oil industry, he has participated in exploratory drilling operations—primarily in remote areas of South America—and

held various drilling research and development positions. His focus has been on exploration and drilling, starting with geolo-gy and moving through geomechanics, drilling, and modeling, to drilling dynamics and drilling systems automation. Macpher-son has published approximately 40 papers, and has more than 25 granted patents. He serves as chairman of the SPE Drilling Systems Automation Technical Section and is a member of the Drilling Systems Automation Roadmap initiative and the JPT editorial committee.

Deepwater Managed Pressure Drilling and Well Drillability, Efficiency, and Process Safety

Adoption of the applied surface-backpressure types of man-aged pressure drilling (MPD) technologies in deepwater have mainly involved the use of a rotating control device (RCD). The RCD creates a closed drilling system in which the flow out of the well is diverted toward an automated MPD choke mani-fold (with a high-resolution mass flowmeter) that aside from regulating backpressure also increases sensitivity and reduc-es reaction time to kicks, losses, and other unwanted drilling events. This integration of MPD equipment into floating drill-ing rigs to provide them with MPD capabilities, including the capacity to perform pressurized mud cap drilling and riser gas mitigation, has produced improvements not only in drill-ability and efficiency, but most importantly in process safe-ty. Case histories will be presented on how MPD has enabled drilling to reach target depth in rank wildcat deepwater wells, increased drilling efficiency by minimizing nonproductive time, enhanced operational and process safety, and provided riser gas mitigation capabilities that can detect a gas influx once it enters the drilling fluid stream.

Julmar Shaun Sadicon Toralde is the glob-al champion for deepwater MPD, downhole deployment valve, and steady-state continu-ous flow system technologies for Weather-ford in Houston. He helped to pioneer deep-water MPD deployment on a dynamically positioned drillship in 2010 and is actively

involved in major deepwater MPD rig integration projects glob-ally. He holds a geothermal engineering degree from Negros Oriental State University in the Philippines. Toralde has written approximately 50 technical papers and trade journal articles and led a number of MPD training courses.

Integrated Reservoir Modeling in Carbonates—Quo Vadis?

Integrated reservoir modeling (IRM) is a best practice in the upstream industry, which is applied through all life-cycle stages of oil and gas projects to help characterize subsurface reservoirs and optimize field development phases. In this respect, carbon-ate and clastic reservoirs are different in a range of aspects that will be highlighted. During the past 25 years, major develop-ments in technology have proven the importance of IRM as a subsurface contributor to upstream projects. A brief history of IRM will be provided, using exploration examples from carbon-ates and development examples that progress up to the recent learnings about unconventional hydrocarbon trapping. More importantly, these industry showcases will be used to intro-duce present-day challenges facing IRM. Despite the significant progress in modeling technologies, the root causes for the dis-appointing results of such studies are the limitations in software

tools and workflows and the lack of integration. An outlook for the future of hydrocarbon development planning and IRM will be presented.

Jürgen Grötsch is global learning advisor for geology at Shell, where he is responsible for the design and deployment of advanced training programs. In this position, his focus areas are integration and building capabilities in decision-based subsurface modeling for multidisciplinary teams. He

holds a PhD in carbonate sedimentology and has authored and coauthored numerous publications and books. Grötsch is well-known as a keynote lecturer from international geoscience con-ferences and since 2009 has been a visiting lecturer at the GeoZentrum of the Universität Erlangen-Nürnberg in Germany. He is vice president of the German Geological Society.

Integration From Multiple Disciplines in Horizontal Well Evaluations To Increase Production in Organic Rich Shales

Drilling horizontal wells is the common mode of operation for field development in permeability-challenged unconven-tional reservoirs such as an organic shale. Assumptions are made regarding the homogeneity of the reservoir as wells are drilled away from the vertical pilot well. It is assumed that the reservoir characteristics remain uniform and that the structure is known to remain in a constant orientation based on the dip information at the pilot wellbore. Expe-rience tells us that these assumptions can lead to wells placed out of zone and in rocks with much different reser-voir quality and stress magnitude, which can adversely affect the well’s production potential. Lateral measurements and petrophysical interpretations can be used to define varia-tions in reservoir and completion quality, which can be used to optimally place perforation clusters in similar rock to increase production vs. peer geometric wells. A methodol-ogy to integrate data from many sources enables a better understanding of the variability and structural challenges of these complex reservoirs. This integrated methodology has been refined using learnings from various case studies that show increased production compared with results from geo- metric completions.

Kevin Fisher is a senior petrophysicist at Schlumberger in Houston, with 25 years’ experience in petrophysics and rock phys-ics. He works in the South Texas Production Technology Integration Center where he focuses on unconventional resource plays, mainly in the Eagle Ford Basin. Fisher’s fur-

ther areas of expertise have been deepwater and shelf struc-tures in the Gulf of Mexico; tight gas sands in south Texas and the Rockies; Alaska; the Permian Basin; unconventional gas

and oil shales; coalbed methane; and international, including Australia, Brazil, Argentina, the United Kingdom, France, Nigeria, Angola, Turkey, and Saudi Arabia. A petroleum engi-neering graduate of the University of Tulsa, he has been a guest lecturer at Rice University since 2012 for a graduate petroleum geology class titled Economic Geology—Petroleum.

Drilling Dynamics—Five Fundamental Questions Answered

Understanding downhole dynamics is a key to reducing down-hole failure and nonproductive time. Damage resulting from drilling dynamics costs the industry in excess of USD 750 mil-lion annually in repair and maintenance alone, and total costs are higher when reduced drilling efficiency and added trips related to failures are included. The presentation answers five fundamental questions about drilling dynamics: 1) What is it? 2) How do we know it is happening? 3) What are the conse-quences? 4) How can it be predicted? 5) What can be done to prevent it?

Liam Lines is the global SME for drilling mechanics and vibration at Weatherford Drilling Services. He is charged with advanc-ing the company’s understanding of the drilling environment, developing and evalu-ating new downhole logging-while-drilling (LWD) and rotary steerable technologies,

and defining best-practice guidelines for drilling optimization and hazard mitigation. Lines has a number of patents pending and has presented a series of technical papers at international conferences. He has a master’s degree in mechanical engineer-ing from the University of Bristol and a PgCE in petroleum engi-neering from Heriot-Watt University.

The Science and Economics of Multiphase Flow

We are familiar with the production systems through which reservoir fluids flow to reach processing facilities. This journey is characterized by complex multiphase flow phenomena that govern pressure and temperature changes along the way. Over the past 50 years, a monumental amount of research and devel-opment work has been invested in better understanding multi-phase flow behavior. Yet, many challenges remain as we strive to optimize complex production systems fraught with difficult flow assurance issues. Just how good is the science? And more importantly, how does this impact our bottom line? The lecture will discuss key concepts of multiphase flow that lead to today’s “state-of-the-art” models. Looking to the future, the science must be advanced to address areas of greatest uncertainty and align with trends in field development strategy. Recommenda-tions will be presented covering the top five areas of research necessary for these purposes.

Mack Shippen is a principal engineer with Schlumberger in Houston, where he is responsible for the global business of the PipeSim multiphase flow simulation soft-ware. He has extensive experience in well and network simulation studies, ranging from flow assurance to dynamic coupling of

reservoir and surface simulation models. Shippen has served on a number of SPE committees and chaired the SPE Reprint Series on offshore multiphase production operations. He holds BS and MS degrees in petroleum engineering from Texas A&M University, where his research focused on multiphase flow modeling.

How Can Microfracturing Improve Reservoir Management?

Microfracturing is an excellent method of obtaining direct stress measurements, not only in shales but also in conven-tional reservoirs. Recent advances have shown that micro-fracturing can help improve reservoir management by guiding well placement, completion design, and perforation strategy. Microfracturing consists of isolating small test intervals in a well between inflatable packers, increasing the pressure until a small fracture forms and, by conducting a few injection and shut-in cycles, extending the fracture beyond the influence of the wellbore. This talk describes the microfracturing process and presents several examples that led to increased hydro-carbon recovery by efficient stimulation and/or completion design. Case studies presented range from optimizing hydrau-lic fracturing in unconventionals, determining safe waterflood injection rates in brownfields, and improving perforation placement in ultradeep water reservoirs.

Mayank Malik is the global formation test-ing expert at Chevron Energy Technology Company and is a champion for advancing research on microfracturing. He holds a BS degree in mechanical engineering from Delhi College of Engineering, an MS degree in mechanical engineering from University

of Toronto, and a PhD in petroleum engineering from the Uni-versity of Texas at Austin. Malik has authored numerous papers on petrophysics, formation testing, and microfracturing. He serves on the SPE Reservoir Description and Dynamics advisory committee and is the chairman of the SPWLA Formation Test-ing Special Interest Group.

Applications and Advantages of LWD in High-Angle and Horizontal Wells

The drilling industry has undergone a revolution in the past decade, with horizontal drilling becoming the norm for the development of many unconventional and conventional res-

ervoirs. Horizontal wells pose unique challenges for log inter-pretation and formation evaluation. Most of the logging tech-nology in use was developed for evaluating vertical wells. The measurement responses observed in horizontal wells are often different from vertical wells in the same reservoir. It is important to understand how standard logging “quad-combo” measurements are affected by the orientation change from vertical to horizontal. Sometimes these changes are misinter-preted or assumed to be tool malfunctions. By understanding the changes in the measurement responses, we can take full advantage of the information they provide to understand the formations surrounding the borehole. This talk will address some of these issues and discuss the various applications for real-time LWD measurement to improve drilling efficiency and safety.

Michael Gillen is the global director for for-mation evaluation services at Baker Hughes. With 34 years of logging and formation eval-uation experience, Gillen began his career as a field engineer with Dresser Atlas in 1981. He later joined Numar, where modern nuclear magnetic resonance technology was

first developed for well logging. Joining Baker Hughes in 2000, Gillen was responsible for introducing several new wireline technologies before moving to the Drilling Services group to lead the LWD team. He holds a BS degree in engineering from the University of Colorado and an MBA degree from Pennsylva-nia State University. Gillen has published several papers on new wireline and LWD technologies and interpretation techniques and holds two patents in the field.

Stress Shadows: How and Why They Can Affect Hydraulic Fracturing in Both Conventional and Unconventional Plays

Much is now made about “stress shadows” and their impact on hydraulic fracturing, particularly in multistage horizontal lat-erals commonly used in unconventional formations. Unfortu-nately, there is no standard definition of stress shadows and, thus, much confusion over what they are and are not, and most importantly, why they can have a significant impact on hydraulic fracturing. The goal of the presentation is to address this confusion and more fully explain stress shadows and their impact. The creation of hydraulic fracture width during a stimulation generates a change in the stress field, which alters all three principal stresses as well as tip shear stresses. These stress changes are the stress shadows.

Neal Nagel is chief engineer for OilField Geomechanics and has nearly 30 years of industry experience. He is a well-known expert in the geomechanics of unconven-tional reservoirs and has given many invited SPE, AAPG, HGS, SEG, and SPWLA presen-

tations. Nagel has also authored or co authored more than 50 technical papers, with more than 20 related to unconvention-als—including a keynote presentation at the 2014 SPE Hydrau-lic Fracturing Technical Conference. He is a past SPE Distin-guished Lecturer, was chief editor of the 2010 SPE Monograph on Solids Injection, has served on the SPE Drilling and Comple-tions committee, and has been an SPE section officer.

Prediction and Management of Fines Migration for Enhanced Oil and Gas Production

Fines migration is the most common formation damage mechanism that challenges the economic viability of petro-leum development projects. The phenomenon has been wide-ly reported for production and injection wells, drilling, com-pletion, waterflooding, and pressure depletion with water support. It is explained by the lifting of reservoir fines, their migration and pore plugging with consequent decline in per-meability. We introduce a maximum retention function for fines that models fines mobilization and allows coreflood interpretation, well impairment history analysis, and well behavior prediction, with laboratory and field case studies presented that validate the approach. The reservoir study pre-sented shows how to use the coreflood- and well-history data for reliable prediction, prevention, and mitigation of produc-tivity decline. The traditional view of fines migration is to avoid it because of its detrimental effect on reservoir permea-bility and well productivity. However, the permeability decline effect provides a relatively simple method for water mobility control. We show laboratory and field cases where, compared with “normal” waterflooding, the fines-assisted low-salinity waterflood results in a significant increase in reservoir sweep because of fines lifting and permeability decline in the swept zone. Reliable prediction of productivity decline because of fines migration and its effective management to enhance pro-duction is the key message of the lecture.

Pavel Bedrikovetsky is professor of petro-leum engineering at the University of Ade-laide. He has authored a seminal book on reservoir engineering and more than 200 papers in international journals and SPE venues. Bedrikovetsky’s research covers formation damage, waterflooding, and

EOR. He holds an MSc in applied mathematics, a PhD in fluid mechanics, and a DSc in petroleum engineering from the Rus-sian Gubkin Oil and Gas University. Bedrikovetsky was a visit-ing professor at Delft University of Technology and Imperial College of Science and Technology. He has 35 years of industry experience in Russia, Europe, Brazil, and Australia. Bedrik-ovetsky serves as a short course instructor and has been a pro-gram committee member at numerous SPE conferences. He was a 2008–2009 SPE Distinguished Lecturer.

Two Vital Secrets for Building Better Type Wells

Each year, companies use averaged well production (type wells) to support billion-dollar expenditures to buy and develop oil and gas resources. These type wells often have unrepresenta-tive rate-time profiles and recoveries that are overstated by up to 50%. These intolerable errors result from common, but incorrect, assumptions in constructing type well production profiles, and the selection and weighting of analog wells. Lit-erature related to constructing type wells is sparse and incom-plete. The lecture will fill that gap and lead participants to informed decisions for best practices in type well construction. Hindcasting examples show that when type well construc-tion combines historical and predicted production rates, only small errors in recovery result. This improvement stems from using educated estimates (not intrinsic values) for months with no data to average, and from individual well forecast errors that offset one another. A Monte Carlo method incorporates risk and leads to better well selection and weighting factors, achieving more representative rate-time profiles. The recom-mended methodology incorporates aggregation and choosing different uncertain parameters. Parameter choice is impor-tant because it makes little sense to risk recovery (e.g., P90 for proved reserves) when the application demands a different parameter such as present value.

Randy Freeborn is an SME in empirical forecasting, type wells, and related technol-ogy. He is chief research engineer at Energy Navigator, where he is responsible for iden-tifying and inventing engineering technolo-gy for inclusion in the company’s reserves management software. He has been a pro-

fessional engineer for 44 years and is a member of SPEE and SPE. Freeborn has prepared numerous technical papers for presentation at conferences, workshops, and industry meet-ings. He has given guest lectures at the University of Houston and  Texas A&M University and has been called as an expert witness.

Creating Value From Uncertainty and Flexibility

An increasing number of oil and gas companies use deci-sion analytic methods to deal with complex and uncertain decisions, but they still yield consistent underperformance in typical business metrics (cost, production rates, time to start, etc.) leading to less value than expected, or, more per-niciously, than possible. Uncertainty per se is not the culprit, rather a failure to make the best decisions under uncertain-ty—which are often nonintuitive. The real value-destroyers are bias and failing to plan for, and exploit, the different ways reality might evolve. If you underestimate the real uncertain-ty, you are likely to underinvest in managing its consequenc-es. Making the best decisions requires an accurate assessment

of uncertainty (unbiased, neither optimistic nor pessimistic) and an unbiased approach to managing its consequences—putting as much effort into capturing upside opportunities as into mitigating risks. The talk will illustrate and discuss how to create value from uncertainty and flexibility by apply-ing an option-pricing methodology that explicitly focuses on upside possibilities.

Reidar B. Bratvold is professor of petro-leum investment and decision analysis at the University of Stavanger. Before his career in academia, Bratvold spent 15 years in the industry in various technical and management roles. He is a coauthor of the SPE book Making Good Decisions. Bratvold

has twice previously served as an SPE Distinguished Lecturer. He is the 2015 recipient of the North Sea Region SPE Manage-ment and Information Award and serves as the executive editor for the SPE Economics & Management Journal. Bratvold is a Fel-low of the Society of Decision Professionals and a member of the Norwegian Academy of Technological Sciences. He holds a PhD in petroleum engineering and an MSc in mathematics, both from Stanford University, and has  studied business and man-agement science at INSEAD and Stanford.

Human Factors in Barrier Thinking

The oil and gas industry places great reliance on layers of defenses, or barrier thinking, to protect against process safe-ty incidents. Human performance continues to be the single most widely relied on barrier, whether as a defense in its own right, or in implementing, inspecting, maintaining, and sup-porting engineered defenses. Human error, in its many forms, also continues to be a significant threat to the reliability of engineered and organizational defenses. While approaches to developing and assuring layers-of-defenses strategies have become increasingly formalized and rigorous in recent years, many organizations struggle to know how to ensure that the human defenses they rely on are as robust as they reasonably can be when those strategies are developed and implemented. Drawing on the 2005 explosion and fire at the Buncefield (UK) fuel storage site as a case study, the presentation considers issues associated with the independence and effectiveness of human defenses. The key idea SPE members should take away from the lecture is that organizations can improve the strength of their human defenses by being clearer about exactly what it is they expect and intend of human performance to protect against threats.

Ron McLeod is honorary professor of engineering psychology at Heriot-Watt University. He has more than 30 years’ experience as a human factors specialist and was Shell’s global discipline lead for human factors until March 2014. McLeod

has been active in organizations including the UK National Advisory Committee on Human Factors, the Process Safety Leadership Group, the International Association of Oil and Gas Producers, SPE, and the Chartered Institute of Ergo-nomics and Human Factors. He has published in scientific journals and has authored or contributed to numerous tech-nical standards and best-practice guides. McLeod’s first book, Designing for Human Reliability: Human Factors Engineer-ing in the Oil, Gas, and Process Industries, was published by Elsevier in 2015. He holds a BSc degree in psychology, an MSc  degree in ergonomics, and a PhD in engineering and applied science.

In-Situ Wettability Utilizing Low Gradient Magnetic Resonance

Evidence has shown that mixed-oil-wet reservoirs do exist. How mixed wettability occurs is complex. Water-wet sys-tems can transition to mixed wet, but if we can identify where they occur and know the distribution in the reservoir, we can produce more efficiently. Hydrocarbon recovery, produc-tion mechanisms, and field development economics strongly rely on understanding the wetting characteristics of the in-situ reservoir fluids. This paper presents a new approach to estimate wettability, using low-gradient magnetic resonance technology. Wettability is difficult to measure in situ. Howev-er, the interaction of the fluid and rock mineral surfaces have an apparent relaxation time that is influenced by the surface relaxation mechanism of magnetic resonance. Wettability can be measured in the laboratory through contact angle, atomic forces microscope imaging, and Ammot index measurements. These are scale-constrained, and it is difficult to replicate original downhole conditions for these measurements. The new approach enables direct wettability estimation at in-situ reservoir conditions. A spin-lattice function is derived, which is directly related to the interfacial tension and surface wet-ting fluid properties. A wettability index is then computed from the function using a reference zone below the free water level. The results indicate mixed wetting characteristics in asphaltenes and heavy-to-solid hydrocarbon bearing sections.

Oluwasegun Jebutu is a regional manager at Baker Hughes with more than 28 years’ industry experience in reservoir character-ization supporting wireline and LWD opera-tions. His roles have included strategic senior manager, global integration manag-er, reservoir development services, regional

geoscience manager—North America, district petrophysicist, petrophysical and project consultant, operations manager, and integrated field studies. Jebutu has a BSc degree in physics, an MSc degree in petroleum engineering, and an MBA, all from Texas A&M University. He has authored patents on NMR tech-nology and coauthored more than 40 publications. An SPE Dis-tinguished Lecturer in 2011–2012, Jebutu is a member of SPE

and SPWLA. He has been an SPE conference chairman and a section chairman.

Dry Hole Analysis: What I have Learnt About the Upstream Petroleum Industry From my Failures

Finding and producing oil and gas are the major objectives of any upstream company. However, both can be highly elu-sive. Dry hole analysis is an exploration methodology to deter-mine what can be learnt from drilling failures. Using a series of case studies from my own career, I look at what we can learn from “failures”—not just those that occur during explora-tion, appraisal, and development but also those that relate to the business as a whole. Having worked for all types of com-panies—multinationals (European and US), Australian com-panies, and even my own consultancy—I have been exposed to many and varied management and organizational models. In each case, the distilled learnings are universal and applicable at any stage of a career. Originally prepared as a young petro-leum professionals lecture, the concepts discussed have been expanded to help all professionals see the upstream petroleum industry as a business. As well as uncovering technical find-ings from failures, we can also find out a great deal about the industry that will help working in it become more rewarding and exciting.

Steve Mackie has more than 35 years’ expe-rience in the upstream petroleum industry in regional and field-specific geoscience and engineering. In addition to running a con-sultancy, he has worked with multinationals and local explorers in technical and mana-gerial roles. He is an adjunct at the Austra-

lian School of Petroleum, University of Adelaide; a member of the Advisory Board to the Australian School of Petroleum; and chairman of the Australian Petroleum Production and Explora-tion Association (APPEA) technical program committee. Mack-ie serves as editor of the APPEA Journal and is the federal presi-dent of the Petroleum Exploration Society of Australia. He is an honorary life member of APPEA and an active member of SPE, AAPG, and  EAGE. Mackie has a BSc degree in geophysics and sedimentology, an MBA degree in strategy, and a PhD in deci-sion making.

Borehole Seismic Solutions for Integrated Reservoir Characterization and Monitoring

Modern field management increasingly relies on detailed, precise 3D reservoir characterization and timely areal moni-toring. Borehole seismic techniques bridge the gap between remote surface seismic observations and downhole reservoir evaluation. Borehole seismic data provide intrinsically higher- resolution, higher-fidelity images than surface seismic data in the vicinity of the wellbore and unique access to proper-

ties of seismic wavefields to enhance surface seismic imaging. With the advent of new, operationally efficient, and very large wireline receiver arrays, fiber-optic recording using distrib-uted acoustic sensing (DAS), the crosswell seismic reflection technique, and advanced seismic imaging algorithms such as reverse time migration, a new wave of borehole seismic tech-nologies is revolutionizing 3D seismic reservoir characteriza-tion and on-demand reservoir surveillance. The lecture will begin by illustrating the wide range of borehole seismic solu-tions for reservoir characterization and monitoring, using a diverse set of current- and recent case study examples—through which the audience will gain an understanding of the appropriate use of borehole seismic techniques for field devel-opment and management. The lecture will then focus on DAS, explaining how the technique works and its ability to deliver conventional borehole seismic solutions (with key advantages over geophones), and will describe DAS’ dramatic impact on field monitoring applications and business-critical decisions.

Steve Morice is a lead geophysicist and Shell’s global focal-point specialist for well-to-seismic interpretation. With 20 years of experience in the international oil and gas industry, he has contributed to the fields of surface and borehole seismic survey design, acquisition technologies, process-

ing/imaging techniques, and geophysical interpretation—with emphasis on the integration of surface and borehole data for field development and production optimization. He is an author or coauthor of numerous technical publications and holds two patents. Morice has a PhD in geophysics from Cam-bridge University.

Minimize Operational Risk Using Shared Geomechanical Earth Model

Stuck drillpipe, lost hole, severe mud losses, unable to hydrau-lically fracture the formation, well shut down because of sand production, early water breakthrough. Sound familiar? These incidents can cost E&P companies millions of dollars. Geome-chanics combines geology, geophysics, petrophysics, and rock mechanics to describe state of earth stresses and rock mechan-ical properties. This can be done along a single wellbore or in 3D field scale, and the results are presented in the shared geo-mechanical earth model. The model helps in the understand-ing and managing of the risks associated with rock deforma-tion, which help to minimize operational risks for the life of the field from exploration to abandonment. Examples include wellbore instability, sand production, hydraulic fracturing, injectivity, subsidence, compaction, fractures reactivation, and thermal effects. The presentation aims to increase aware-ness of how one and the same shared geomechanical model can be used by different departments in an E&P company for their operational planning, with focus on drilling and comple-tion activities.

Surej Kumar Subbiah is the principal geo-mechanics lead in the Middle East at Schlumberger and is based in Abu Dhabi. He spent the first 5 years of his career in an academic environment as a research associ-ate and a lecturer before joining Schlum-berger. With 20 years of experience, Subbiah

has been involved in many applied geomechanics projects from well-centric to 3D field scale, and conducted training courses in geomechanics for NeXT Oil and Gas Training and Competency Development (a Schlumberger company), SPE Netherlands, and SPWLA Abu Dhabi. He holds BS and MS degrees in petroleum engineering from the University of Technology in Malaysia, with specialization in geomechanics.

Your Field Is Getting Older: Is Your Process Engineering Still Cost-Effective?

The lifecycle of developed fields, onshore and offshore, will go through different stages of production up to the decline into late field life. Effective reservoir engineering management will lead to prolonging the life of field if a cost-effective processing surface facilities strategy is put in place. Factors that lead to the decline in oil production or increase in operating expense (Opex) may include increased water production, solids han-dling, and the need for relatively higher compression require-

ments for gas lift. To maintain productivity and profitability, an effective holistic engineering approach to optimizing the processing surface facilities must be used. Successful operation of mature fields and their surface facilities requires success-ful change management to the new operating strategy. Using a holistic approach can maximize the full potential of mature pro-cessing facilities at a manageable Capex and Opex.

Wally Georgie is principal consultant at Maxoil Solutions and specializes in separa-tion, produced fluid, and gas handling. He has worked for more than 37 years in differ-ent areas of oil and gas production facilities, including corrosion control, flow assurance, fluid separation, separator design, gas han-

dling, and produced water. Georgie started his career in oil and gas services in 1978, based in the UK and working globally with different production issues. He then joined Statoil as senior staff engineer and later as technical advisor in the Norwegian North Sea. In 1999, he began work as a global consultant in off-shore and onshore operations, conventional and unconvention-al separation troubleshooting, operation assurance, produced water management, gas handling problems, flow assurance, system integrities, and production chemistry, with an emphasis on mature facilities. Georgie holds a BSc degree in chemistry, MSc degrees in polymer technology and safety engineering, and a PhD in applied chemistry.