Distinguished Lecturer Slides/Graphics
Each year, SPE selects peer-nominated professionals to share their knowledge and expertise with SPE members. View available slides and support materials from previous lectures.
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Water-injection is commonly employed to supplement reservoir energy and improve sweep efficiency in oil developments. In such applications, the injectivity and longevity of water injectors drive productivity and recovery. However, injectors are vulnerable to impairments, resulting in their gradual injectivity decline and possible catastrophic failure. To maximise value from water injectors, a holistic understanding of their impairment mechanisms is imperative.
This lecture examines injector impairment, and the conditions under which an injector fails. With impairments broadly classified into hard and soft mechanisms, both classes are explored, while elucidating the main factors controlling each of these. Options to mitigate impairments are discussed, while laboratory and field examples are reviewed. The main take-away from this lecture is a better understanding of how to competitively improve the performance and longevity of water injectors. Relevant tips include (i) robust network design, well planning and delivery; (ii) high-quality injection water; (iii) effective surveillance; (iv) management of operating envelopes; and (v) maximising uptime. Accounting for injector impairments in production forecasts, as well as providing injector redundancy and intervention budgets are considered good practices to deliver credible business plans, hence safeguarding incremental reserves linked to water-injection projects.
Following a 10-year stint in Shell Nigeria, Kazeem A. Lawal is currently the Head of Reservoir Engineering at FIRST Exploration & Petroleum Development Company, Nigeria. He holds a BSc degree in chemical engineering from the Obafemi Awolowo University (Nigeria), as well as MSc and PhD degrees in petroleum engineering from the University of Port Harcourt (Nigeria) and Imperial College London, respectively. He has extensive experience in reservoir engineering, spanning the industry, academia and consulting. He has authored more than 40 technical papers, and served as a technical reviewer for journals and conferences. He received the 2014 SPE-Africa regional award in reservoir description and dynamics.
When the price of oil plunged in 2014, industry analysts predicted that shale plays would be shutdown as they would no longer be economical. In reality, the North America shale industry did not just survive, it thrived. How?
The most successful companies responded by exercising capital discipline and effectively managing their resources. As a result, breakeven prices for the key unconventional plays were decreased by 40-60%. Reduction of service pricing alone cannot account for the improvement in profitability relative to oil price. What other factors contributed?
This presentation captures the key lessons learned. The organizational, operational, and technological advancements which allowed the shale industry to continue to thrive in a “lower for longer” price environment are illustrated through case histories. Geologists worked to identify each play’s core, while companies evolved from delineation to full field development. The synergistic effect of combining new technology with operational efficiency is illustrated by the ability to drill longer laterals with significant decreases in drill days. Completion optimization, fueled by the use of big data analytics, resulted in drastic increases in EUR allowing expansion of the core in many plays. Improvements in artificial lift technologies accelerated early time production, significantly increasing the net present value of capital employed. Throughout all of these processes, cooperative relationships between the service sector and E&P companies was imperative to the continued success of the industry.
Can the lessons learned by the shale industry be applied in the global setting? Absolutely.
Mary Van Domelen holds a BS in Chemical Engineering from the University of Oklahoma. She is a licensed Professional Engineer and a SPE Certified Petroleum Engineer with over 35 years experience. Mary started her career with Halliburton in research and operations roles based in the USA, Europe, Africa, and Middle East. She has held engineer advisor and management roles with innovative E&P companies such as Maersk Oil, Chesapeake, and Continental Resources. Her experience includes horizontal drilling and completion operations in multiple basins. She has co-authored more than 30 papers and holds several patents. Mary was a 2015-2016 SPE Distinguished Lecturer and was the 2016 SPE Mid-Continent North America Regional Completions Optimization and Technology Award recipient.
Asphaltenes have been viewed as enigmatic; in fact, asphaltenes exhibit remarkable, reliable systematics for oil reservoirs around the world. The recently developed Yen-Mullins model specifies three distinct species of asphaltenes in crude oils, one for light oils, a second for black oils, and a third for heavy oils. With this knowledge, a simple polymer solution theory is modified for application in oilfields, the Flory-Huggins-Zuo Equation of State. Equilibrated asphaltenes imply reservoir connectivity addressing at an early stage a very important risk. Asphaltene disequilibrium identifies recent or ongoing reservoir fluid processes in geologic time, shown to impact all crude oil components. Corresponding reservoir case studies allow codifying the new discipline ‘reservoir fluid geodynamics.’ Incorporation of the charge history context with asphaltene thermodynamics clarifies key reservoir attributes for production. Fault block migration is shown to be recorded in gradients of asphaltenes and other fluid components. Gas or condensate charge into oil reservoirs often leads to large, disequilibrium fluid gradients yielding asphaltene migration to the base of the reservoir. This asphaltene accumulation leads to heavy oil and tar mat formation, greatly affecting field development planning. Analysis of adjacent reservoirs in different phases of the same process provides the industry’s first “movie” of tar mat formation, albeit only two time frames. Incorporation of asphaltene thermodynamics and reservoir fluid geodynamics aids in analysis of all manners of reservoir concerns.
Dr. Oliver C. Mullins is a Schlumberger Fellow and member, U.S. National Academy of Engineering. He led the inception and development of Downhole Fluid Analysis (DFA) in well logging. Dr. Mullins also leads an active research group in petroleum science leading to the Yen-Mullins model of asphaltenes and the Flory-Huggins-Zuo Equation of State. His current interests include utilizing DFA technology and new asphaltene science to perform novel reservoir evaluation. This work is subsumed in the newly codified technical discipline he is leading “reservoir fluid geodynamics” that accounts for processes dictating fluid and tar distributions in oilfield reservoirs; this is the subject of his latest book. He has won several awards including the George A. Olah Award in Hydrocarbon or Petroleum Chemistry from the American Chemical Society and the SPWLA Gold Medal for Technical Achievement. He has been Distinguished Lecturer 7 times for SPWLA and SPE (currently for SPE). He authored the award-winning book The Physics of Reservoir Fluids; Discovery through Downhole Fluid Analysis, coedited 3 books and coauthored 14 chapters on asphaltenes and related topics. He has coauthored 275 publications, ~½ on petroleum science, ~½ on oilfield applications, and has coinvented 119 allowed US patents. He has accumulated 17,000 citations on Google Scholar to his work. He is Fellow of two professional societies and is Adjunct Professor of Petroleum Engineering at Texas A&M University.
Current compositional simulators include compositional equation-of-state fluid models, but do not account for compositional effects on relative permeability, capillary pressure, and grid-block flux calculations. Relative permeability, for example, is still based on “old thinking” related to labeling of phases as “oil, gas, and water.” Labeling causes significant discontinuities that can result in inaccuracies and instability in simulations of compositional processes, such as those for enhanced oil recovery (EOR).
This presentation will show you why labeling is “old thinking” and how labeling generates discontinuities and simulation errors in compositional processes. Several example cases, including water-alternating-gas and surfactant flooding, are given using a new type of compositional simulator with all labels removed. One component of the novel simulator is the development of an equation of state (EoS) for relative permeabilities that eliminates phase labeling. The relative permeability model is physically based and captures complex hysteresis effects through saturation and phase connectivity as well as changing wettability, interfacial tension, and pore morphology. Results show increased robustness, improved accuracy, faster computational times, and less instabilities when phase labeling is removed.
Russell T. Johns is the George E. Trimble Chair of Energy and Mineral Sciences at the Department of Energy and Mineral Engineering at The Pennsylvania State University. He also holds the Energi Simulation Chair in Fluid Behavior and Rock Interactions. He recently served as Chair of the Petroleum and Natural Gas Engineering Program, and is currently the Editor-In-Chief for SPE journals.
Prior to his current position at Penn State, he served on the petroleum engineering faculty at The University of Texas at Austin for fifteen years. He also has nine years of industrial experience as a petrophysical engineer with Shell Oil and as a consulting engineer for Colenco Power Consulting in Baden, Switzerland. He holds a BS degree in electrical engineering from Northwestern University and MS and PhD degrees in petroleum engineering from Stanford University. He has over 250 publications in enhanced oil recovery, thermodynamics and phase behavior, unconventional gas engineering, multiphase flow in porous media, and well testing.
Dr. Johns received the SPE Ferguson medal in 1993, the SPE Distinguished Member award in 2009, the SPE Faculty Pipeline award in 2013, the 2016 SPE international award in Reservoir Description and Dynamics, and the 2018 Wilson Excellence in Research award from the College of Earth and Mineral Sciences. He is currently director of the Enhanced Oil Recovery consortium in the EMS Energy Institute at Penn State University.
Increasing challenges and complex environments in the exploration and production of oil and gas require pioneering technologies, innovative processes, and mega projects that only knowledgeable, highly skilled professionals can deliver.
Human performance improvement methods were utilized to develop structured professional development paths aligned to business-line goals of preparing large cohorts of entry-level professionals to replace the mature workforce while upskilling experienced and senior technical employees. The value proposition was to reduce time to competency and engage employees in career-long development using a dual-curriculum program tied to effective job performance in job roles carried by petroleum engineers and geoscientists. The developed program was sequential; an early-career performance-based curricula for professionals out of college followed by mid-to-senior level curricula.
The presentation highlights challenges with competency-based training, the shift to a performance-based approach, and a development program alignment with the business to reduce time-to-competency for young professionals from an industry average of 7 years to 4 years with over 90% program completion. Shared program methodology, implementation, and lessons learned will provide a basis for others to deploy, replicate, and scale.
Salam Salamy is a Senior Petroleum Engineering Consultant for Saudi Aramco with over 30 years of industry experience. He has lead the Saudi Aramco Upstream Professional Development Center (UPDC) since 2010. In practice, Salam focused on horizontal well technology and petrotechnical professional development. He is the author and co-author of over 30 technical publications.
Salam participated in the 2004-2005 SPE Distinguished Lecturer Program. He received the 2009 SPE Distinguished Member Award and 2006 Middle East Region Service Award. Salam also served on the SPE Distinguished Lecturer Selection Committee. He now serves as an SPE/ABET Program Evaluator.
The formation of scale deposits upon tubing, casing, perforations, and even on the formation face itself, can severely constrict fluid flow and reduce the production rate of oil and gas wells. In addition to lost production, a considerable portion of the workover budget is expended in efforts to remove these deposits and prevent their recurrence. As a consequence, scale prevention has been and continues to be a common exercise and is successfully applied in many areas. Although the principles behind scale formation and prevention are generally well understood, there are many new forms of scale prevention and new scale inhibitor application technologies. Some people consider scale prevention a mature subject matter area with “nothing new under the sun,” but in fact there are many new developments, some of which will be highlighted in this presentation. This presentation will review the major elements that normally comprise any effort aimed at the successful control of scale deposition, starting with scale identification, followed by scale prediction, inhibition, and removal. Several case histories will illustrate the application of these scale control techniques in oil production facilities. Scale formation can be a show stopper, but if properly managed, scale can be prevented economically.
Charles Hinrichsen earned a BS degree in Chemistry from the State University of New York at Stony Brook and an MS and PhD in Chemistry from Cornell University. He worked at Texaco and later Chevron for forty years at Chevron’s Energy Technology Company as a Chemical Treating Specialist. From 1998–2001 he coordinated Texaco’s chemical operations in Angola, West Africa, and from 2001–2003 he served as Senior Corrosion and Chemical Treating Engineer in Wafra, Kuwait. He has over 38 years of experience in scale and corrosion control treatment and is a member of the Society of Petroleum Engineers, the American Chemical Society, and the National Association of Corrosion Engineers.
Non-technical or external stakeholder risks have become a dominant factor in the upstream business. Especially capital projects may experience significant schedule delays or cost overruns due a variety of issues of governmental, social, environmental, security or other external nature. Delegating your response to External Affairs or hiding behind a Corporate Social Responsibility program is no longer good enough. Adequate addressing of non-technical risks, both mitigating downsides and benefiting from upsides, can be done, but needs an advanced level of internal organization and a culture that accepts external stakeholder perspectives. Technical functions need to take an active role and responsibility in addressing non-technical risks and need to work closely together with commercial and externally facing functions. Christiaan Luca will give you practical tips on how to organize internally for effective addressing of non-technical risks and how to minimize undesired surprises from external stakeholders. The important role of management and the technical functions will be a key element of this lecture. A solid external response requires a solid internal organization
Christiaan Luca, Community Wisdom Partners, graduated with a BSc in mining engineering and a MSc in petroleum engineering, both from Delft University, the Netherlands. The first 14 years of his 32-year career with Shell he spent overseas in a variety of petroleum engineering roles, including drilling, reservoir engineering, project planning and economics developing oil and gas fields in Thailand, Syria, Gabon and Nigeria. Upon returning to Shells corporate offices in the Netherlands he held various management roles in technology and business strategy and planning. In these positions he was closely involved with externally challenged programs in CCS and Rigs-to-Reefs. Until end 2016, Christiaan was the head of Shells global practice in non-technical risk management. He now is an independent trainer, assessor and coach in this expertise area.
Formation Testers (FT) have been around for more than 50 years. Early 1990s, have seen the emergence of pumpout wireline formation testers (WFT) which modernized their applications, including better fluid sampling, permeability and anisotropy measurements and basic downhole fluid analysis. Now, the technology is advancing further in both hardware and software as we are entering a new era in formation testing. While the industry is pushed to reduce costs, compromises on reservoir and fluid characterization can have detrimental effects in new projects and emerging FT applications are well poised to provide critical answers to reduce asset uncertainties. In this lecture, we will briefly focus on existing and emerging hardware/ software on formation testing but our focus will be on applications of acquired and interpreted data for reservoir and fluid characterization. We will discuss pressure gradient analysis and implications of gradient errors for reservoir engineers. We will review the effects of OBM contamination on fluid uncertainties and the choice of inlet types on cleanup behavior. Emerging downhole fluid analysis sensors will be discussed and a new deep transient testing method will be introduced. In-situ stress testing with WFT will be outlined with drilling and reservoir engineering applications. We will discuss these points with field examples. Finally, desired features of next generation WFT will be outlined.
Cosan Ayan was a Reservoir Engineering Advisor for Schlumberger Wireline Headquarters based in Paris, France, who has opted for early retirement in June 2017. Cosan had several international assign-ments covering Houston-USA, Indonesia- Jakarta, United Kingdom-Aberdeen, UAE-Abu Dhabi, and Egypt-Cairo. He holds BS degree from Middle East Technical University, Ankara, MS and Ph.D. degrees from Texas A&M University, College Station all in Petroleum Engineering. He is the author of more than eighty-five technical papers on Well Testing and Reservoir Engineering and was a SPE Distinguished Lecturer during 2005–2006. Cosan served as an Executive Editor for SPE REE Journal from 2007–2010 and edited SPE e-book volumes on “Getting Up-To-Speed: Formation Testing”. Cosan received the SPE Formation Evaluation Award, September 2015.
The Intergovernmental Panel on Climate Change (IPCC) and the International Energy Agency (IEA) have issued recent reports suggesting that deployment of carbon dioxide capture and storage (CCS) can significantly reduce the cost of achieving CO2 emission reduction targets. However, several questions remain: Under what circumstances will large-scale deployment take place? Where and when will this occur? How large a role will CCS play in stabilizing atmospheric concentrations of CO2? I will review the current status of CO2-EOR and geologic storage focusing on subsurface lessons learned and their implications for large-scale CCS. Our industry has a long history with CO2-EOR that provides a strong experience base for CO2 storage. However, CO2-EOR alone will be insufficient to meet emission reduction targets and storage in deep saline aquifers is also being investigated. Experience from operating CCS projects shows that subsurface storage capacity in saline formations can be limited by dynamic injectability factors. Hundreds of years of CO2 storage capacity is potentially available, even after accounting for dynamic limitations, but the areal distribution of potential storage capacity is widely varied. Geologic and reservoir engineering studies will be essential for identifying storage sites having adequate capacity, containment, and injectivity. Petroleum engineers will play a key role in these studies.
Gary Teletzke is Senior Technical Advisor for Enhanced Oil Recovery at ExxonMobil Upstream Research Company. He has led research projects related to gas injection EOR, chemical EOR, and compositional reservoir simulation. He has also led several EOR field studies, integrating laboratory work, reservoir simulation, and pilot testing. For the past ten years, he has provided technical leadership to research efforts on CO2 sequestration. He has published more than 40 technical papers and patents. He has organized numerous SPE conferences over the past two decades and served as Executive Editor of SPEREE from 2015–2017. He was named an SPE Distinguished Member in 2013. He received a BS in chemical engineering from Northwestern University and PhD in chemical engineering from University of Minnesota.
Global climate change remains top of the agenda for lively discussion on TV documentaries, frightening newspaper headlines, science magazines and foreign policy journals. The sudden abundance of relatively clean and inexpensive shale oil and gas is profoundly changing global energy markets. Despite the rapid growth of renewable energy, the fact remains that fossil fuels will continue to dominate world energy consumption for decades to come. Therefore, fossil fuel consumption will continue to produce greenhouse gas emissions that are linked to global warming. Public and political pressure, however, is to curtail the use of oil and gas hydrocarbons or find solution for permanent disposal of heat trapping gases. This is no longer an option for the future; it is a political necessity. Carbon dioxide sequestration and storage presents a huge challenge for research and development. Massive projects will eventually be required, leading to many opportunities, new businesses and specialized services. Most of these activities will fall on the shoulders of petroleum engineers and geologists. This presentation provides a view on global climate change issues, starting with causes and effects, the positions of believers and skeptics and the often contradictory arguments of scientists and policy makers, with the likely political consequences for the petroleum industry.
George Stosur managed oil and gas R&D programs at the U.S. Department of Energy in Washington, D.C. for 22 years. He was responsible for DOE-sponsored research at universities, National Laboratories and joint R&D projects with several countries. Other experience includes Chevron and Shell Oil R&D in EOR, heavy oil, and the first trial of using nuclear explosive to fracture ultra-low permeability formations. He served as an SPE Section Director, SPE Distinguished Lecturer and guest speaker for several cruise lines. Authored 86 papers and contributed to a five-volume encyclopedia on hydrocarbons. He holds two MS degrees and a PhD in petroleum engineering.
All oil & gas wells produce sand—either a little or a lot! Conventional sand control, which includes production limits or completions, has two downsides: 1. neither method achieves maximum production; 2. both methods fail at some point - allowing solids to overwhelm the surface facility.
Solids handling then becomes an expensive maintenance problem, HSE incident, or downtime production loss. What if the facility handled sand without interruption or equipment downtime? Even better, what if sand co-production improved recovery or restarted shut-in wells? Facilities Sand Management (FSM) skillfully handles solids to sustain production while minimizing the effects on operations. FSM methodology uses five discrete steps: Separation, Collection, Cleaning, Dewatering, and Transport. All steps must be followed, with a focus on the approach—not a piece of equipment. Separation removes sand and solids from the flow stream, while Collection gathers the solids into a central location and isolate them from the process. Cleaning, if required, removes associated oil and Dewatering removes associated liquids—both to simplify handling and minimize handling volume. Transport brings the solids to disposal location, which may be discharge, landfill, ship-to-shore, or injection. Each step is integral to simplify operations and extend equipment life, and all steps can be incorporated into new or existing facilities. Solids handling should not be viewed as a waste stream treatment problem – it is a critical flow assurance task. FSM provides a degree of skill to solids handling to sustain flow in surface operations and enhance production.
Hank Rawlins is the Technical Director of eProcess Technologies with 25 years’ experience in the upstream oil & gas industry. He actively conducts research in Facilities Sand Management, Produced Water Treatment, and Compact Separations Systems and blogs weekly, teaches courses, and has fifty-six publications on these topics. Hank served as the chair of the SPE Separations Technology Technical Section (2013–2015), was an SME Henry Krumb Lecturer (2011–2012), and co-authored the PEH Chapter on Produced Water Treatment. Dr. Rawlins holds a PhD in Metallurgical Engineering from the University of Missouri-Rolla, is a registered Professional Engineer, and serves as adjunct professor at Montana Tech.
The foundation of modern geochemical logging for concentrations of elements in earth formations emerged in the 1990s. The additional information provided by geochemical logs makes it possible to account for complex and variable mineral mixtures during the formation evaluation process. This added value wasn’t fully recognized until the early 2000s when the petroleum industry began increasing its focus on unconventional reservoirs. Today, geochemical logs have become a valuable exploration tool to enable accurate formation volumetric analyses in both conventional and unconventional reservoirs. The presentation briefly discusses neutron-induced gamma ray spectroscopy measurement theory, which is the cornerstone of modern geochemical logging instruments, and the flow of data from the raw measurement to elemental concentrations. Log examples show how geochemical logs can be used to identify the presence of common minerals in sandstone, carbonate, and organic shale reservoirs. The example logs also show how geochemical and traditional logs can be used in combination to carry out a complex reservoir volumetric analysis. When working in unconventional reservoirs, a well-defined workflow can be used to obtain formation evaluation results that compare favorably with core porosity, grain density, and matrix mineralogy from X-ray diffraction measurements. A new development makes it possible to use geochemical logs to assess the reliability of lithodensity photoelectric (PE) logs in wells drilled with moderate-to-heavy mud weights. In deepwater exploration where heavy muds are used and PE logs may not be available, a substitute PE log can be derived from geochemical logs.
Jim Galford is a Chief Scientific Advisor for the nuclear physics group in Halliburton’s Sensor Physics team. He holds a BS degree in physics from West Virginia University. His career began in 1975 as a Schlumberger field engineer. He joined Halliburton via their acquisition of NUMAR in 1997. He has written 29 technical papers on magnetic resonance imaging and nuclear logging applications. He holds 15 patents and he has 14 additional patents pending. He received a Distinguished Technical Achieve-ment Award from the Society of Petrophysicists and Well Log Analysts (SPWLA) in 2017. He has been a member of the SPWLA for 35 years and the Society of Petroleum Engineers for 37 years.
The drilling industry faces challenging market conditions that motivate the use of automation to reduce costs and decrease well manufacturing variability. The objective of this presentation is to motivate automation initiatives that utilize physics-based models for predictive monitoring and control. This presentation explores current progress, challenges, and opportunities to control critical drilling conditions such as downhole pressure in Managed Pressure Drilling (MPD). The 3 essential elements of automation are explored with a perspective on recent advancements in automation due to downhole measurement availability through wired drillpipe. However, only a small fraction of drilling systems currently utilizes wired drillpipe. In automated rig systems, there is additional potential to unlock the predictive capabilities of physics-based models to “see” into the near future to optimize and coordinate control actions. A convergence of several key technologies creates an opportunity to use sophisticated mathematical models within automation. A significant challenge is the size of the physics- based models that have too many adjustable parameters or are too slow in simulation to extract actionable information. This presentation shows how fit-for-purpose models can be used directly in the automation solutions. These fit-for-purpose models have unlocked new ways to think about automation in drilling. For example, rate optimization and pressure control have traditionally been separate applications in MPD. Simulation studies suggest significant potential improvement when combining the two applications.
John Hedengren is an Assistant Professor in the Department of Chemical Engineering at Brigham Young University. He received a PhD degree in Chemical Engineering from the University of Texas at Austin. Previously, he developed the APMonitor Optimization Suite and worked with ExxonMobil on Advanced Process Control. His primary research focuses on accelerating automation technology in drilling. Other research interests include fiber optic monitoring, Intelli-fields, reservoir optimization, and unmanned aerial systems. In addition to drilling automation, he is a leader of the Center for Unmanned Aircraft Systems (C-UAS), applying UAV automation and optimization technology to energy infrastructure.
Rocks deep in the earth have unique and enigmatic material properties due to the confining pressures in the earth. Confining pressure increases rock strength and changes rock from a brittle to a ductile material. Humans tend to think of rock as brittle, since all of our direct experience with rock is at atmospheric pressure. But as wells were drilled deeper into the earth, it became apparent that the rock drilled in oilfield wells yielded much lower penetration rates than rocks of the same composition near the surface. About seventy years ago, researchers in drilling mechanics began to study this by building high-pressure test facilities in which rock could be confined and drilled. Even with these new test machines, researchers had to hypothesize what was happening to the rock at the bottom of the borehole because they could not observe the drilling process first-hand. Though they understood that rocks under confining pressure become ductile, they continued to form hypotheses based on brittle failure mechanics. This presentation reviews the detective-story history of model development to explain low rate of penetration in deep boreholes. It then describes our current industry understanding of rock failure in a borehole, which includes a significant role played by crushed rock detritus. Current challenges facing the drilling mechanics community are identified. This presentation constitutes a plea for continued research in this area.
Roy Ledgerwood earned a BS in Mechanical Engineering from Texas Tech University in 1975 and began working for Hughes Tool Company Research. Bob Cunningham, one of the pioneers in oil-field drilling mechanics, mentored him. In 1987, Ledgerwood earned an MS in Mechanical Engineering from Rice University where he studied drilling mechanics with Dr. John Cheatham, another pioneer in the field. When Hughes Tool Company built its Full-scale High Pressure Drilling Simulator—a test facility in which may stress rock up to 15,000 psi and test bits as large as 12¼”—Ledgerwood was the first super-visor of the facility. He designed and performed unique tests to show that crushed rock detritus in a borehole has a strength on the same order of magnitude as the original rock at the instant it is created. Ledgerwood has collaborated with other similar laboratories in Salt Lake City, Tulsa, and Pau, France in joint-industry and proprietary tests. In addition to testing, Ledgerwood has modeled the drilling process with both Finite Element Analysis and Discrete Element Analysis. These mathematical models show that most of the energy expended while drilling a deep well is dissipated not in failing the rock, but in extruding crushed rock detritus. He holds 14 patents and is the author of 23 technical papers.
As the development of oil and gas reservoirs continues around the world, the need for innovative solutions to economically produce these reservoirs remains as strong as ever. Building a talent base within an organization is paramount for this task. The successful exploitation of these often- challenging plays will require completion engineers who can implement new technologies and function within a multidisciplinary work environment. This presentation will describe technical training options and available resources for developing high performing completion engineers within an organization. A case study of an advanced engineering training program implemented within a major service company will be presented, along with recommendations for external training and development programs. Our industry faces several challenges related to advanced engineering training and technology application including generation gaps brought about from industry downturns, global expansion of unconventional reservoir plays, cost constraints, and the complex nature of the reservoirs we work in today. Companies that recognize this changing landscape and focus their efforts on engineering development will be rewarded with a more productive workforce, higher retention of their technical employees, and a more seamless transition through the years ahead.
Mark Van Domelen is an industry-recognized expert in hydraulic fracturing and well completion methods. He is currently the Vice President of Technology for Downhole Chemical Solutions, and worked for Halliburton for 31 years in a variety of roles including engineering, technology, operations management, supply chain, and training positions. Nearly half of Mark’s career has been spent in international positions in The Netherlands, Angola, Egypt and Denmark. Mark has a degree in Mining Engineering from the University of Wisconsin-Madison and has been a member of SPE since joining the industry in 1984. He has authored or co-authored 17 industry papers and has served on several committees for the Society of Petroleum Engineers. Mark is passionate about training young professionals and spent the past several years developing and implementing an advanced engineering training program called the College of Completions Engineering for Halliburton engineers in the area of unconventional reservoirs. He has also recently published two SPE papers on the topic of multidisciplinary training, and participates as a mentor for young engineers through the SPE Trailblazer and E-Mentoring programs.
This presentation will show how time-lapse or 4D seismic data can be used as an additional constraint to history match reservoir models in a 4D Seismic History Matching (4D SHM) workflow. 4D seismic provides an independently measured and spatially extensive dataset that complements the field’s production data. It is sensitive to fluid saturation and pressure changes and provides information on the dynamic behavior of the reservoirs. It is also sensitive to the geological properties and informs the geological model too. 4D SHM is the process of developing reservoir models that are consistent with both the observed production data and the 4D seismic data. When 4D seismic data are available the reservoir model can be used to generate synthetic 4D data. Discrepancies between those two datasets are used to update the models and to attain a seismic history matched simulation model. A case study will be presented where 4D SHM was applied to the Harding and Gryphon fields in the North Sea. It was used to develop regional geological and simulation models for a major gas development project. The combination of geological knowledge, reservoir simulation and 4D SHM led to greater confidence in the final models. 4D SHM is an evolving technology, so the presentation will conclude with a discussion on the current status of the technology and some of its research and development directions.
Paul Mitchell is the Discipline Lead for Geophysics at TAQA in the UK. He has broad ranging responsibilities and is a technical authority for geophysics within the company. Paul has thirty years of experience in exploration, development and production geophysics from around the world. He spent a number of years working in ExxonMobil’s Upstream Research Center in Houston specializing in seismic depth imaging, 3D volume interpretation and 4D seismic. He is currently working within a multi-disciplinary team developing subsurface models for a large gas development project in the North Sea. His current interests are in 4D seismic and its application to 4D Seismic History Matching and he has presented his work at numerous international conferences. He holds a B.Sc. in Physics from the University of Southampton and a M.Sc. in Exploration Geophysics from Imperial College in London. He is the Founding President of the EAGE Local Chapter in Aberdeen and is Chair of the SPE Seismic2018 conference.
Multi-stage unconventional hydraulic fracturing treatments require pumping large volumes of water based fluids. As the industry continues to develop extremely low permeability reservoirs increasingly larger water based fluid treatments are being pumped. These large treatments also lead to varying flowback issues ranging from high to low load fluid recoveries. In many cases, either by design or controlled by operational restrictions, wells can undergo weeks or months of shut-in following these very large treatments. In most cases, these shut-in wells have demonstrated significant upticks in production resulting in some operators reporting an enhancement to hydrocarbon recovery. The reasons for the low and inefficient water recovery after fracturing are only now being understood. Some researchers believe that low water recovery is due to water retention in secondary fractures or unstable displacement and gravity segregation in fractures. Others believe the retained water in the reservoir can leak-off into the rock matrix due to water imbibition. Yet, in many cases, there are no negligible effects on long term productivity. The dynamics of shut-in time permits the imbibition process to evolve; allow-ing water to move deeper into the water-wet/clay-rich formation. This results in lower water saturation and a corresponding higher gas/oil relative permeability near the fracture surface. In contrast, if the well is not shut-in, capillary forces are balanced by viscous forces, thereby trapping water at much high-er saturations around the fractures and reducing hydrocarbon flow potential.
Robert Hawkes graduated from the Southern Alberta Institute of Technology in Calgary, Alberta, Canada with a diploma in Petroleum Engineering Technology in 1979. Robert has authored and co-authored over 20 papers and was co-author, Chapter 3 “Gas Well Testing and Evaluation” of the 2007 Modern Fracturing—Enhancing Natural Gas Production, engineering text book. Robert’s role at Trican Well Service in Calgary is Reservoir Engineering Advisor for their Geological and Reservoir Engineering Service group. Robert has been the recipient of numerous awards and was a Distinguished Lecturer with SPE in 2008. In 2011, Hawkes was the recipient of the SPE Canadian “Reservoir Description and Dynamics” award and recently was recognized for his achievement as the recipient of the 2016 Canadian “Completions Optimization and Technology” award. Robert has served on a multitude of SPE workshops and conferences and was the Program Committee Chairman for the 2013 Hydraulic Fracture Flowback Workshop.
Oil price developments over the past 45 years have been truly spectacular. In constant money, prices rose by 759% between 1970–1972 and 2012–2014. This can be compared with a price index for metals and minerals, which increased by a mere 38%. Analysis shows that the exceptionality of oil’s upward price push over the past decades cannot be adequately explained by cost-raising depletion or by OPEC interventions. The better explanation is an inadequate development of production capacity, caused by above-ground hurdles; e.g. onerous fiscal regimes and conflicts over resource rents. Despite past experience, a turning point has been reached where scarcity, uncertain supply and high prices will be replaced by abundance, undisturbed availability and suppressed price levels. Technical advances in drilling and hydraulic fracturing, which led to fast rising oil and natural gas production in the US but is also applicable to unconventional and conventional formations worldwide, will assure ample and diversified future supply. Although short-run price spikes may occur, oil prices are unlikely to prevail above the total production costs of new supplies, which are estimated to settle at $40–60/barrel in the coming two decades. Expanding global gas output and trade will likely depress gas prices as well. It is concluded that oil and gas will continue to play an important role in satisfying energy demand, from Asia to the Americas, with innovation that will allow for economic production in spite of low prices.
Roberto F. Aguilera is a Research Fellow with Curtin University, Australia. From 2013–2017, he was an analyst with the OPEC Secretariat, Vienna, and a co-author of their annual World Oil Outlook. Previous affiliations include IIASA, University of Vienna, Catholic University of Chile and Servipetrol. He has participated in numerous energy studies, including with the World Petroleum Council and US National Petroleum Council. He holds PhD and Master degrees from Colorado School of Mines and a Bachelor’s from Haskayne School of Business, University of Calgary. His publication record comprises The Price of Oil, a book published by Cambridge University Press (2015).
For more than 50 years, coiled tubing has been an intervention technology primarily used to maintain or increase production, fulfilling the vital requirements for intervening on live wells. However, the downhole parameters during a conventional coiled tubing operation are only inferred through surface-measured parameters, such as coiled tubing weight and length and pumping pressure, leading to uncertainties regarding the operation’s actual progress and outcome. In order to increase certainty in unknown downhole conditions, enhance safety and efficiency, and reduce the operational time and cost, coiled tubing telemetry technologies have been developed in the last 10 years and used for a wide range of coiled tubing applications. These systems, consisting of downhole tools with sensors and electronics, data transmission media through the coiled tubing such as optical fiber, wire, or both, and surface hardware and software, provide real-time monitoring of single-point data such as pressure, temperature, depth correlation, tool force and torque, inclination and acceleration, etc., and distributed temperature and acoustic data along the coiled tubing. This lecture will provide a brief introduction of coiled tubing history and current status, before describing the coiled tubing telemetry technologies and their game-changing advantages comparing to conventional coiled tubing. Several case histories will exemplify how the real-time coiled tubing telemetry information improves well intervention operations by making decisions based on dynamic downhole events and eliminating missed or wasted runs. The lecture will conclude discussing how coiled tubing telemetry is transforming the coiled tubing opera-tions and its growing significance within the current industry trends leading to a severe shortage of experienced coiled tubing personnel.
Silviu Livescu is the chief scientist in the global Coiled Tubing Research and Engineering center of Baker Hughes, a GE Company, in Calgary, Canada, with fundamental and applied research, industrial research and development, innovation, commercialization, and intellectual property experience mainly related to Production and Operations. Silviu is an executive editor for the Journal of Petroleum Science and Engineering and an associate editor for the SPE Journal, and serves on the SPE Production and Facilities advisory committee and the SPE Journal of Petroleum Technology editorial committee. Silviu received the SPE Canada Region Production and Operations award in 2017 and the SPE ‘A Peer Apart’ award in 2015.
Big data analytics has become quite the buzzword in recent years, and its growing application in E&P operations promises to be an exciting new development. It involves: (1) acquiring and managing data in large volumes, of different varieties, and at high velocities, and (2) using statistical techniques to “mine” the data and discover hidden patterns of association and relationships in large, complex, multivariate datasets. The ultimate goal is to extract as much intelligence from our ever-expanding trove of data to improve operational efficiencies and make better decisions for optimizing the performance of petroleum reservoirs. However, the subject remains a mystery to most petroleum engineers and geoscientists because of the statistics-heavy jargon and the use of complex algorithms. In this talk, I will provide a “gentle” introduction to big data analytics by focusing on: (a) easy-to-understand descriptions of the commonly-used concepts and techniques, (b) broad categories of E&P problems that can be solved with big data analytics, and (c) case studies demonstrating the value-added proposition for big data. The one key idea I would like to offer as a takeaway is this: There is significant potential for data analytics to provide insights that can be translated into actionable information in E&P projects, but petroleum engineers and geoscientists need to have a fundamental understanding of data-driven modeling concepts, their applicability and limitations.
Srikanta Mishra is Institute Fellow and Chief Scientist (Energy) at Battelle Memorial Institute, the world’s largest independent contract R&D organization, where he manages a geoscience-oriented technology portfolio related to computational modeling and data analytics for geological carbon storage, shale gas development and improved oil recovery projects. Dr. Mishra is the author of “Applied Statistical Modeling and Data Analytics for the Petroleum Geosciences” recently published by Elsevier, and has also taught multiple short courses on uncertainty quantification, statistical modeling and data analytics. He holds a PhD degree in Petroleum Engineering from Stanford University.
Industry studies show that mature fields currently account for over 70% of the world’s oil and gas production. Increasing production rates and ultimate recovery in these fields in order to maintain profitable operations, without increasing costs, is a common challenge.
This lecture addresses techniques to extract maximum value from historical production data using quick workflows based on common sense. Extensive in-depth reservoir studies are obviously very valuable, but not all situations require these, particularly in the case of brown fields where the cost of the study may outweigh the benefits of the resulting recommendations.
This lecture presents workflows based on Continuous Improvement/LEAN methodology which are flexible enough to apply to any mature asset for short and long term planning. A well published, low permeability brown oil field was selected to retroactively demonstrate the workflows, as it had an evident workover campaign in late 2010 with subsequent production increase. Using data as of mid-2010, approximately 40 wells were identified as under-performing due to formation damage or water production problems, based on three days of analyses. The actual performance of the field three years later was then revealed along with the actual interventions performed. The selection of wells is compared to the selection suggested by the workflow, and the results of the interventions are shown. The field's projected recovery factor was increased by 5%, representing a gain of 1.4 million barrels of oil.
Anne Valentine is a Principal Instructor for Production Engineering at Schlumberger. She has 35 years of experience in Canada and France in well and reservoir performance analysis, particularly related to waterflooding, unconventional reservoirs and candidate recognition for production enhancement. She built her expertise in performance analysis workflows and software through working on the Cold Lake heavy oil field as a reservoir and field engineer at Esso Resources Canada Limited, then consulting for Halliburton before joining Schlumberger in 2001. A graduate in Chemical Engineering from Queen’s University in Canada, she has co-authored papers on analysis techniques for polymer floods, waterflood optimization and shale gas forecasting.
In 2010 Shell began investigating how to automate the initial response to a well control incident. The first phase of the project was to develop a rig system that could reliably detect an influx across a broad spectrum of floating rig well construction related rig operations. The results of a fault tree style sensitivity analysis pointed to the high value of improving sensor data quality (both accuracy and reliability) and the importance of improving kick detection software for alarming (both in terms of coverage and how the driller is alerted to respond to a confirmed kick condition). Based on the analysis results, a Smart Kick Detection System functional specification was developed and used to upgrade the kick detection system on an offshore rig.
Early in the project it was realized that focusing on adding robust kick detection during connections was important but especially challenging due to the associated transient flow and pit volume signatures. A separate in-house initiative was therefore kicked-off to develop new software based on pattern recognition technology and machine learning. The resulting IDAPS (Influx Detection at Pumps Stopped) software has now been implemented as a real-time monitoring application for all Shell operated deep water wells. Further developments in smart kick detection are coming, ultimately leading to rigs being equipped with automated kick detection systems that are relied upon to detect a kick and secure the well in case the driller fails to act.
Brian Tarr is a Senior Well Engineer based in Houston, Texas. His long career has included assignments in both drilling and completion operations and he has managed several significant technology projects related to well construction process safety, including the first surface BOP implementation for a deepwater subsea develop (offshore Brazil) and the design and construction of compact, modular, subsea capping stacks (for deployment in the North Sea and offshore S.E. Asia). Mr. Tarr has previously served as both a review committee chairman and a technical editor for the SPE Drilling and Completion magazine. He has also been active in both IADC and API well control related committees, including contributing to the 2nd edition of the IADC Deepwater Well Control Guidelines and to API RP 96, Deepwater Well Design and Construction. He has a Master of Petroleum Engineering degree from Heriot Watt University, Edinburgh Scotland, and is a registered professional engineer in Texas.
In these times of low oil and gas prices, the drive to provide 'more for less' has never been greater. One key component in achieving this is the ability to accurately monitor the production rates along a wellbore and across a reservoir. Ideally a range of different measurements should be available on-demand from all points in all wells. Clearly conventional sensors such as downhole pressure and temperature gauges, flow meters, geophone arrays and production logging tools can provide part of the solution but the cost of all these different sensors limits their widespread deployment. Fibre-optic Distributed Acoustic Sensing, or DAS for short, is changing that. Using an optical fibre deployed in a cable from surface to the toe of a well DAS, often in combination with fibre-optic Distributed Temperature Sensing (DTS), provides a means of acquiring high resolution seismic, acoustic and temperature data at all points in real-time. Since the first downhole demonstrations of DAS technology in 2009 there has been rapid progress in developing the technology and applications, to the point where today it is being used to monitor the efficiency of hydraulic fracture treatments, provides continuous flow profiling across the entire wellbore and is used as a uniquely capable tool for borehole seismic acquisition. With optical fibre installed in your wells and DAS acquiring data, there is now the ability to cost effectively and continuously monitor wells and reservoirs to manage them in real-time in order to optimise production.
David Hill is co-founder and Chief Technology Officer at Sintela Systems. He has over 30 years of research and development experience in the field of acoustic sensing, 20 years of which have been spent developing fibre-optic based sensors. He holds a PhD in Physics, specializing in fibre-optic sensing, from the University of Kent in the UK and has filed over 30 patents and authored numerous papers. He has led the development and exploitation of fibre-optic Distributed Acoustic Sensing (DAS) in the oil and gas industry and in 2009 he was the first person to use fibre-optic Distributed Acoustic Sensing (DAS) to acquire signals on a downhole fibre. Since then he has continued to develop a range of downhole applications for the technology.
Oil and gas are essential parts of a sustainable future. Though these are finite energy resources and sources of greenhouse gas emissions, the world continues to require their production. For this reason, it is imperative that we consider improved industry practices.
To begin, the audience will be presented with the most basic principles of sustainability pertaining to oil and gas operations, including SPE’s position on this matter. When oil is discovered at a location, decisions and guarantees cannot be made without considering the project’s life cycle. Our commitments must be demonstrated consistently along each stage of a project in direct consideration of a sustainable future.
Next, several case studies relating to sustainability, integrating the realities of the social license to operate and operations will be presented to the audience, detailing the required steps for the successful execution of any project facing challenging conditions.
The presentation will conclude by underlining that the inclusion of internal and external stakeholders will only enrich the project and, therefore, pave the road to success. It is our responsibility to create a culture of operational professionalism and reliability through active participation. In order to counterbalance the world’s energy demand, we must produce oil and gas while considering that the more efficiently the energy is produced, the more affordable the energy will be. The oil industry is not only committed to its own sustainability but also to the sustainability of our planet.
An HSE Manager with PetroEcuador, Fernando L. Benalcazar has been in the oil industry for 25 years and has provided project management and support for numerous international projects in Syria, France, Canada, the US, Oman, Venezuela, Colombia, and Ecuador. Benalcazar focuses on operation excellence, sustainable development, and stakeholder engagement. He also specializes in health, safety, and environment (HSE), local content, capacity building, and new ventures. He has authored or coauthored more than 12 technical papers and holds a MS degree in civil engineering from Alberto Luiz Coimbra Institute for Graduate Studies and Research in Engineering (COPPE) at the Federal University of Rio de Janeiro, Brazil. He holds a Certified Safety Professional (CSP) designation in the US and is member of the Board of SPE Sustainable Development Technical Section and has served on it since 2012. He is currently President of SPE Ecuador Section and has acted as member of its Board since 2011. Benalcazar was the chair of a SPE Applied Technology Workshop and of two Latin American and Caribbean regional conferences. He has been a chairperson for the environmental focus area of the SPE International HSSE-SR Advisory Committee since 2015.
"Drilling" often refers to all aspects of well construction, including drilling, completions, facilities, construction, the asset team, and other groups. Good performance measures drive performance and reduce conflict between these groups, while bad performance measures mislead and confuse. The first key to success is how to communicate drilling performance in terms that answer the questions of executives and managers, which requires a business-focused cross-functional process. The second key to success is to drive operational performance improvement, which requires a different set of measures with sufficient granularity to define actions. Over the past 10 years, a very workable system has evolved through various approaches used in drilling more than 16,000 wells in the US, South America, and the Middle East. The system has delivered best-in-class performance. It has proven that an effective performance measurement system which addresses both executive requirements and operational requirements can both deliver outstanding results, and also communicate those results, with remarkable value to the organization. The basic principles are widely applicable to areas other than drilling.
John Willis is Drilling & Completions Manager for Occidental Oil & Gas Corporation Permian Resources Delaware Business Unit. His responsibilities include drilling, fracturing, completions, and well servicing in the Delaware Basin. Prior to this role, he served as Chief of Drilling for Oxy for 6 years, responsible for standards, operational support, global systems, the drilling data system, and tools for drilling performance measurement. He also served as Drilling Manager in Oman and Drilling Manager in Libya. His experience prior to Oxy includes other drilling roles, service company roles related to project management and software development, and he operated a consulting and software business. He has Chaired two SPE Forums, served on Forum Steering Committees, and Chaired the 2003 SPE/IADC Drilling Conference.
In low oil-price environments, it is customary to cut expenses, reduce staff, and postpone most, if not all, capital investments. While this strategy may be financially sound in the short term, it is ineffective in the long run, particularly for companies with the need to sustain production levels or to replace reserves through drilling, production or reservoir projects. Heavy oil projects are usually more challenging, as production costs are higher and the oil price is even lower.
This presentation addresses the dilemma of controlling cost and at the same time sustaining production and increasing recovery. A balance can be struck by focusing on the quality of decisions, such as when and where to invest, and ensuring that projects are delivered on- budget, a common issue in the E&P industry. The central idea in this presentation is that, in the most complex and financially challenging case of Enhanced Oil Recovery (EOR) projects, the combination of quality decision making and the implementation of “fit-for-purpose” technology offers the most promising middle-point. By providing eight examples of innovative technologies to help reduce uncertainty, cost and time for delivering commercial EOR oil, and three successful case studies, the audience will gain confidence in the proposition that it is perfectly viable to double recoveries for many of our fields in the next 15 years, even in the current price scenario.
Finally, EOR is a business, and as such it needs to compete favorably with other businesses in a company’s E&P portfolio - challenging in low oil price environments. The lecture will close by presenting a strategy, illustrated with an example, on how to divert from the traditional engineering approach in favor of a managerial decision approach, that will help engineers to justify viable recovery projects.Jose Gonzalo Flores is an independent consultant and instructor in production and reservoir engineering of heavy oils. Previously, he worked for Schlumberger and Occidental Petroleum Corp. covering a 25-year period, in roles involving the structuring, leading, advising and field implementation of production optimization and improved recovery projects, and as instructor for NExT, globally. He is an expert in reservoir engineering and production enhancement, including strategies to increase the recovery factor in heavy oil and mature fields, and has over 45 publications in the literature. Flores received his B.S. degree from the Universidad Nacional de Ingeniería, Lima, Peru, and holds M.E. and Ph.D. degrees from The University of Tulsa, Tulsa, Oklahoma, all in Petroleum Engineering. As a member of the SPE, he regularly serves in steering and technical roles in conferences, forums and workshops. He currently serves on the SPE Editorial Review Committee and was co-chair of the 2016 SPE Latin America Heavy Oil Conference.
Wireline (WL) and Logging-While-Drilling (LWD) formation tester measurements provide a link between the static petrophysical measurements and dynamic rock-fluid properties for enhanced formation evaluation. However, despite the significant advancements in these services, there are still barriers. The analysis of Wireline (WL) and Logging-While-Drilling (LWD) formation testing has traditionally been performed by a skilled testing analyst using specialized software and theoretical models to generate results and assess the data vitality. This can be a time-consuming process involving analyzing over 100 pressure transients. In practice, the petrophysicists and geoscientists rarely have access to a detailed analysis in the time frame required and typically revert to other methods. Some of the methods are ad hoc, but there is a growing consensus that several convenient, simple, and effective real-time measurements can be used for an objective evaluation of the dynamic data. This talk demonstrates a straightforward automated process that has been developed by which real-time measurements, which are routinely recorded, are used to automatically generate the results. Basic principles are used to develop quality parameters and a test rating system that can guide the analyst in the objective determination of the vitality of the results for each test. In this way, the highest quality testing results are used for fluid gradients and log correlations to improve the integration of the dynamic data into the petrophysical analysis. This also enables standards to be established for real-time data acquisition that can save testing time while improving data and quality. This automated method is being applied routinely and several field examples are used to illustrate the utility and time savings of this new workflow.
Mark Proett is a Sr. Petroleum Engineering Consultant for Aramco Services Company, Upstream Group in Houston. Mark is best known for his publications advocating the viability of the formation testing-while-drilling (FTWD) introduced in 2002. He has been awarded 61 US patents and authored over 60 technical papers, most of which deal with sampling and testing analysis methods. He has been an SPWLA Distinguished Speaker and SPE Distinguished Lecturer. In 2008 Mark received the SPWLA Distinguished Technical Achievement Award and in 2013 the SPE Gulf Coast Regional Formation Evaluation Award. Mark has a Bachelor of Science in Mechanical Engineering from the University of Maryland and his Master of Science from Johns Hopkins University.
Big Data is an emerging technology in Information Management that holds promising returns on investment, as it can provide advanced analytics capabilities. It is well suited for large enterprises, and when used properly, it can lead to breakthroughs in analytics, deriving information from data that was previously not possible. However, a Big Data project cannot be approached using traditional IT system design and methods. Its success relies on teamwork and collaboration among petroleum engineering subject matter experts, senior IT professionals, and data scientists. To ensure that Big Data initiatives do not deliver poor results or disappoint, Big Data projects require significant preparation, which dramatically increases the chances of success. This presentation provides practical information about how to get started and what to consider in your plan, and it gives useful tips and examples for planning and executing a Big Data project. At the end of the presentation, attendees will know what Big Data is, what it offers, how to plan such projects, what the roles and responsibilities are for the key project members, and how these projects should be implemented to benefit their organization. Big Data analytics offers enterprises a chance to move beyond simply gathering data to analyzing, mining, and correlating results for insights that translate into business solutions.
Muhammad S. Khakwani is a Senior Information Systems Consultant and the leading Data Architect for Upstream data at Saudi Aramco. He has more than 25 years of experience in the IT industry working for large enterprises in Canada and the United States, and for the last 17 years in the Oil & Gas industry in Dhahran, Saudi Arabia. He has in-depth expertise in database design as well as data management, standardization, and governance. He has designed and implemented data warehouse solutions, formulated Real-Time data strategies, and devised controls for Data Security for Saudi Aramco. His current responsibilities include designing and managing the Upstream enterprise data model, as well as strategizing and managing policies related to the corporate Upstream database necessary to meet changing business needs at Saudi Aramco. He has a BS from University of Western Ontario, and an MIS from Webster University.
Managed Pressure Drilling (MPD) was introduced in 2000 as an adative drilling technology for pricely controlling the pressure profile in the wellbore. Utilizing applied surface pressure, MPD provides an addition degree of freedom in the design and drilling of wells. MPD has been utilized successfully in drilling projects to mitigate or eliminate problems associated with conventional drilling operations. MPD has been used for early kick detection, driling through narrow pore pressure/fracture pressure windows, reduction of the probability of lost returns, identifying and eliminating issues of wellbore breathing (ballooning), and pore pressure/fracture gradient mapping. An area that has great potential, but has gainned little attention, is the ability to utilize MPD for dynamic influx control. MPD changes the primary barrier envelope to well control, allowing small influxes to be managed through the MPD system.
This lecture describes the current state of dynamic influx control and its limitations. It shows how conventional well control practices actually increase the probability of secondary well control problems, and thus risk. The basis for and practical applications of dynamic influx control are presented. Conditions under which dynamic influx control is practicable, and when conventional well control should be invoked, are discussed. Adoption of Dynamic Influx Control eliminates many problems associated with the current conventional methods of well control, allowing the control of the well to be regained safer, quicker and with less risk of secondary problems, including underground blowouts, stuck pipe, lost returns and secondary kicks.
Patrick Brand is a founding partner of Blade Energy Partners and former Drilling Technology Advisor for Mobil. In his 36 years in upstream oil and gas, Patrick has made numerous innovative and fundamental contributions to MPD, including the development of Dynamic influx control, dynamic pore pressure and fracture pressure determination. Patrick is a former Chairman of the IADC UBO and MPD Committee and the SPE Re-Write committee for UBD. Patrick has over 20 archival publications on various technical subjects. Patrick is a registered professional engineer for the State of Texas. Education credits include a BS degree in Civil Engineering from Texas A&M University.
Coiled tubing is a unique fluid and tool conveyance means used to intervene throughout the entire well lifetime. Its flexibility of use is certainly one of the largest in the oil-and-gas industry, ranging from logging to stimulation to cleanout and even drilling. However, for the longest time, it was only seen as a rudimentary fluid conveyance system, despite its capability to service any well deviation.
With the development of instrumented tools for downhole point measurements and the use of fiber optics for distributed sensing, the recent advent of coiled tubing real-time monitoring has completely transformed this image. The access to live wellbore information—such as pressure, temperature, or flow—along with accurate depth control thanks to casing collar locator and gamma ray sensors have greatly enhanced fluid placement. Meanwhile, the ability to monitor the load, torque, and accelerations the bottomhole assembly is subjected to significantly improves the performance and possibility to use and manipulate downhole tools. Thanks to real-time monitoring, a whole new realm of optimization possibility was discovered.
This lecture describes the various real-time measurements that are available today during coiled tubing interventions and how they can be used to provide the industry with faster, safer, and more efficient operations while maximizing return on investment. A wide range of applications and examples will be discussed. Through them, one will be able to appreciate how coiled tubing has now entered a new era where the limits of operational optimization still have not been reached.
Pierre Ramondenc is the Well Intervention Domain Manager for Schlumberger, with over 10 years of oilfield experience. He has been involved in all aspects related to coiled tubing real-time telemetry, from tools creation to intervention design and execution to data interpretation. Pierre has been responsible for defining most of the coiled tubing intervention workflows that leverage real-time data. He has authored over 15 technical papers and patent applications on the topic. Pierre holds MS and PhD degrees in Civil and Environmental Engineering from the Georgia Institute of Technology. He serves as technical editor of SPE Production & Operations Journal.
Increasing interest by governments worldwide on reducing CO2 released into the atmosphere form a nexus of of opportunity with enhanced oil recovery which could benefit mature oil fields in nearly every country. Overall approximately two-thirds of original oil in place (OOIP) in mature conventional oil fields remains after primary or primary/secondary recovery efforts have taken place. CO2 enhanced oil recovery (CO2 EOR) has an excellent record of revitalizing these mature plays and can dramatically increase ultimate recovery. Since the first CO2 EOR project was initiated in 1972, more than 154 additional projects have been put into operation around the world and about two-thirds are located in the Permian basin and Gulf coast regions of the United States. While these regions have favorable geologic and reservoir conditions for CO2 EOR, they are also located near large natural sources of CO2.
In recent years an increasing number of projects have been developed in areas without natural supplies, and have instead utilized captured CO2 from a variety of anthropogenic sources including gas processing plants, ethanol plants, cement plants, and fertilizer plants. Today approximately 36% of active CO2 EOR projects utilize gas that would otherwise be vented to the atmosphere. Interest world-wide has increased, including projects in Canada, Brazil, Norway, Turkey, Trinidad, and more recently, and perhaps most significantly, in Saudi Arabia and Qatar. About 80% of all energy used in the world comes from fossil fuels, and many industrial and manufacturing processes generate CO2 that can be captured and used for EOR. In this 30 minute presentation a brief history of CO2 EOR is provided, implications for utilizing captured carbon are discussed, and a demonstration project is introduced with an overview of characterization, modeling, simulation, and monitoring actvities taking place during injection of more than a million metric tons (~19 Bcf) of anthropogenic CO2 into a mature waterflood.
Longer versions of the presentation can be requested and can cover details of geologic and seimic characterization, simulation studies, time-lapse monitoring, tracer studies, or other CO2 monitoring technologies.
Dr. Robert Balch is the Director of the Petroleum Recovery Research Center located on the campus of New Mexico Tech. At the university he also holds Adjunct Professor positions in Petroleum Engineering and Geophysics and has been research advisor to more than 40 graduate students. During his 20 years at the PRRC he has been principal Investigator on a range of enhanced oil recovery projects focused on developing and applying solutions to problems at many scales using geological, geophysical, and engineering data. Dr. Balch is the Principal Investigator of the Southwest Partnerships Phase III demonstration project where 1,000,000 metric tonnes of anthropogenic CO2 is being injected for combined storage and EOR into a mature waterflood in North Texas. During the course of his work he has published more than 45 papers, is a frequent invited speaker, and has presented his research at more than 100 meetings or events. Dr. Balch has held an appointment as an Oil Conservation Commissioner for the State of New Mexico since June of 2011.
Reservoir engineers cannot capture full value from waterflood projects on their own. Cross-functional participation from earth sciences, production, drilling, completions, and facility engineering, and operational groups is required to get full value from waterfloods. Waterflood design and operational case histories of cross-functional collaboration are provided that have improved life cycle costs and increased recovery for onshore and offshore waterfloods. The role that water quality, surveillance, reservoir processing rates, and layered reservoir management has on waterflood oil recovery and life cycle costs will be clarified. Techniques to get better performance out of your waterflood will be shared.
Scot Buell has worked globally for 36 years as a petroleum engineer. He was a 2005-2006 SPE Distinguished Lecturer, is the author of 12 SPE papers, served as an SPE technical editor for 20 years, and has served as an SPE section Chairman, Forum Chairman, and Applied Technology Workshop Chairman. He has worked as an expert in the design of new waterfloods and the operation of existing waterflood projects in Asia, North America, Europe, and Africa. He provided technical leadership for 30 waterflooded reservoirs offshore West Africa for nine years. He currently serves as a corporate reserves auditor specializing in waterflood and EOR reserve estimates. He also serves as the principal researcher for thermal horizontal wells and thermal subsurface integrity management for Chevron Energy Technology Research Company. He holds a BS and MS in Petroleum Engineering and MS in Petroleum Economics, all from Colorado School of Mines.
Extended-reach wells present difficult drilling challenges, which if inadequately understood and addressed can yield significant downside risks and extensive non-productive time (NPT). These challenges are mainly due to complex well designs that combine high-deviation and extended-reach wellbores with difficult geology and hostile environments. Understanding the challenges and developing solutions are important to deliver the well with the proper casing specifications for production purposes.
Geomechanically, due to their long reaches and high deviations, borehole instability and lost circulations are particularly dominant in the overburden shale sections of extended-reach and horizontal wells. However, a good understanding of the rock failure mechanisms and an innovative use of the wellbore strengthening techniques can mitigate these geomechanical challenges through integration with good drilling practices such as efficient equivalent circulating density (ECD) management and effective hole-cleaning strategies. In addition, the long open-hole exposure typically experienced in these wells can cause chemical, thermal and/or fluid penetration issues that can further complicate the difficult drilling conditions. These secondary influences further stress the importance of incorporating geomechanical understanding in drilling fluids formulation.
This presentation focuses on the geomechanical challenges of drilling extended-reach wells. It highlights the need to integrate geomechanical solutions with appropriate drilling practices, particularly solutions based on good understanding of the intricate relationship between borehole stability, lost circulation, ECD, hole cleaning and bottom-hole assembly (BHA) optimizations in overcoming the drilling performance limiters. A case history will be presented as an example.
See Hong Ong received his B.Sc., M.Sc. and Ph.D. degrees in petroleum engineering from the University of Oklahoma. He has more 30 years of world-wide experience in petroleum engineering and petroleum-related geomechanics research and applications. His professional career includes 17 years at Baker Hughes where he is serving in various advisory, technical and managerial capacities, and 17 years at PETRONAS where he had management and operational responsibilities. See Hong serves on many SPE technical program committees and has recently received the Regional Technical Award in Drilling Engineering. See Hong holds several US patents and has many publications in petroleum geomechanics.
In order to determine a field’s hydrocarbon in place it is necessary to model the distribution of fluids throughout the reservoir. A water saturation vs. height (Swh) function provides this for the reservoir model. A good Swh function ensures the three independent sources of fluid distribution data are consistent. These being the core, formation pressure and electrical log data. The Swh function must be simple to apply, especially in reservoirs where it is difficult to map permeability or where there appears to be multiple contacts. It must accurately upscale the log and core derived water saturations to the reservoir model cell sizes.
This presentation clarifies the often misunderstood definitions for the free-water-level, transition zone and irreducible water saturation. Using capillary pressure theory and the concept of fractals, a practical Swh function is derived. Logs and core data from eleven fields, with very different porosity and permeability characteristics, depositional environments and geological age are compared. This study demonstrated how this Swh function is independent of permeability and litho-facies type and accurately describes the reservoir fluid distribution.
The shape of the Swh function shows that of the transition zone is related more to pore geometry rather than porosity or permeability alone. Consequently, this Swh function gives insights into a reservoir’s quality as determined by its pore architecture. A number of case studies are presented showing the excellent match between the function and well data. The function makes an accurate prediction of water saturations even in wells where the resistivity log was not run due to well conditions. The function defines the free water level, the hydrocarbon to water contact, net reservoir and the irreducible water saturation for the reservoir model. The fractal function provides a simple way to quality control electrical log and core data and justifies using core plug sized samples to model water saturations on the reservoir scale.
Steve Cuddy is an Honorary Research Fellow at Aberdeen University where he holds a doctorate in petrophysics. He also holds BSc (Hons.) in physics and a BSc in astrophysics and philosophy. He is currently a Principal Petrophysicist with Baker Hughes and has 40 Years industry experience in formation evaluation and reservoir description. He has authored several SPE and SPWLA papers and carried out more than 200 reservoir studies.
Over the past few years, significant advancements have been made in completion and stimulation designs in horizontal wells in unconventional plays, with the primary driver being the improvement of fracture contact area in these very low permeability reservoirs, to improve production volumes and recoveries. Fracture contact area with plug-and-perf or sliding sleeve systems have been intensified by increasing the density of contact points in the formation as well as proppant amount with great success. While these parameters have been optimized, other important parameters such as fracture conductivity and connectivity have been largely neglected. In the journey to improving contact area, proppant conductivity is often sacrified to save costs, and fracture stimulation treatments are overflushed in order to maximize operational efficiencies on multi-well pads. This presentation will highlight the importance of all of these parameters, and provides steps that can be taken to further optimize and enhance well producitivity and economics in the shale plays.
Wadhah Al-Tailji is a Technical Manager at StrataGen, where he advises clients on completions and stimulation optimization in unconventional plays such as the Eagle Ford Shale, using fracture and reservoir modeling, analysis of large datasets, and field supervision of hydraulic fracture treatments. Before joining StrataGen in 2010, he spent five years in field and region engineering roles at BJ Services Company in East Texas, where he was involved in stimulation and cementing services in formations such as the Cotton Valley Sands, James Lime, and Haynesville Shale. He has authored three SPE paper on the topics of stimulation evaluation and optimization in the Eagle Ford Shale, and holds B.S. and M.S. degrees in Petroleum Engineering from New Mexico Tech.
Shale development in the US has been ongoing for at least the last decade, and many lessons can be learned from the US experience to help prevent air emissions and aquifer contamination in future developments around the world. Media reports and films such as "Gasland" imply that shale development is widely polluting fresh water aquifers and the atmosphere, with a wide range of estimates of contamination. This lecture examines the risk of contamination of aquifers through wellbores, either by hydrocarbon migration or hydraulic fracturing operations, and is primarily based on a comprehensive three-year study funded by the US National Science Foundation examining nearly 18,000 wells drilled in the Wattenberg Field in Colorado, plus other relevant studies. In the midst of the Wattenberg field is heavy urban and agricultural development, with over 30,000 water wells interspersed with the oil and gas wells, resulting in a natural laboratory to measure aquifer contamination. Lessons learned have universal applications with clear relationships established between well construction methods in both conventional and unconventional wells and contamination risks.
William Fleckenstein is an adjunct faculty member at the Colorado School of Mines, where he served as Interim Petroleum Engineering Department Head 2012-2014, and he also serves as the managing partner in Fleckenstein, Eustes & Associates, consulting on projects worldwide. He holds BSc, ME, and PhD degrees in petroleum engineering and has 30 years experience primarily in drilling, completions and workovers, with direct experience on over 200 wells and involvement in horizontal wells and stimulations since 1990. Dr. Fleckenstein has numerous publications and patented technologies in multi-stage fracturing, annular seal testing, and downhole hydraulic rotation.
Fluids introduced into a wellbore for stimulation applications typically take the path of least resistance and therefore frequently go into areas where there are open flow paths. In many cases, these are neither areas you want to stimulate to enhance production by using a refracturing operation in unconventional reservoirs, nor areas from which formation damage needs to be removed by using an acidizing operation in carbonate reservoirs. Recently developed solid particulate degradable diverters promote efficient plugging, which helps to create nearly impermeable seals and aids fluid diversion. These solid particulate materials are capable of degrading over time from a solid polymer state to a clear, nondamaging, liquid monomer solution, eliminating the need for mechanical removal after intervention.
This presentation describes how different advanced modeling (analytical and numerical), experimental, and field data mining approaches can be used to design and optimize different stages of fluid diversion. Application of lessons learned and engineered design key practices are shown by means of case studies.
Mojtaba P. Shahri is a Senior Geoscientist in the Weatherford RD&E department in Houston, Texas. His current research interests include completion and stimulation design and optimization. He has authored more than 45 technical papers and holds 7 pending US patent applications. Shahri received SPE Star, SPE Henry DeWitt Smith, SPE Nico van Wingen, SPE-GCS Exemplary Volunteer, and SPE Regional Young Member Outstanding Service Awards. He holds a Ph.D. degree in petroleum engineering from the University of Tulsa and is a registered Professional Engineer.
Lost circulation is the most troublesome and costly problem in the drilling operations, cost of material, non productive and lost rig time and lost holes amounts for more than 2,000 M$/year.
Lost ciculation can be categorised into induced losses, and losses occuring in naturally fractured formation. Although some progress using different lost circulation materials and different placement techniques has been done; curing losses is still an art and not a science.
This presentation will cover the lost circulation challenges during the drilling, cementing and the consequences on the long term integrity of the well; and the solutions related to preventing the losses to occur as well as the mitigation meausres to combat the losses when they happen. In addition newly developed solutions, techniques and diagnostic tool to mitigate lost circulation will be presented.
Salim Taoutaou is the Cementing and Well Integrity Technical Advisor for Schlumberger in Paris. He manages the global development of the well integrity cementing domain strategy, providing optimal well integrity cementing solutions for clients. Through his 19 years in the oil and gas industry, he has held various positions in Africa, the North Sea, the Middle East and Asia Pacific. He has authored more than 43 international journal and conference papers, he is the holder of three patents and was the recipient of the SPE 2014 Asia Pacific Regional Technical Award in Drilling Engineering. He received a master’s degree in mechanical engineering from Guelma University, Algeria.
Unconventional development propelled the United States to produce more oil than it imports for the first time in 20 years. Increased production of domestic oil and gas profoundly impacted economic growth and job creation for the U.S. During this evolution, there was a need to address environmental regulations and infrastructure requirements in order to access the sheer volume of resources. Combined with today’s horizontal drilling and hydraulic fracturing technology, a strategic development plan can be constructed for any country to create an unconventional energy opportunity. In this lecture, the experience from U.S development is utilized to provide a fully-integrated workflow for developing shale oil and gas reservoirs from exploitation to production. Starting at the nano-scale, we will zoom into the pore structure to understand the storage and flow paths. Transitioning to the reservoir-scale, well testing and microseismic are utilized to define the flow capacity and estimate the stimulated volume. Learnings from this subsurface characterization is used to guide well completion, flowback, and production operations. The diagnostic methodology specific to each operation can be applied to identify geologically favorable areas and the best completion practice. As development progresses, opportunities to improve recovery can be magnified through optimum well spacing and refracturing. As a final step in the development, determining an appropriate enhanced recovery method is essential to access the remaining resources. Finally, example development scenarios are provided to demonstrate how a technically driven strategy is more effective to maximize value and make the unconventional revolution a global one
Basak Kurtoglu is Vice President in the Global Energy Group of Citigroup Investment Bank. Prior to Citi, she was Integrated Project Team Manager at Marathon Oil. She has been instrumental in assimilating multiple disciplines to evaluate and develop unconventional reservoirs. Kurtoglu earned her BS from Middle East Technical University, and her MS and PhD in petroleum engineering from Colorado School of Mines. Her numerous publications range from pore to reservoir scale analyses of unconventional reservoirs with an emphasis on enhancing oil recovery. She serves on the SPE Forum Series Coordinating Committee and the SPE Reservoir Description and Dynamics Advisory Committee.
The uses of automation in the drilling process are expanding and are typically resulting in improved drilling 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 technical challenges, but instead are related to people issues and the methods for implementing the solutions. 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 automation. 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, Bill spent 20 years building real-time applications and drilling automation systems at National Oilwell Varco. Prior to that, Bill worked as a drilling engineer and as a university researcher. He holds BS, MS, and PhD degrees in Petroleum Engineering from Louisiana State University and is a Registered Petroleum Engineer in Texas. He has authored or coauthored 25 technical papers and holds 15 patents.
The Completion Engineer integrates the requirements of a number of other disciplines (Reservoir, Drilling, Production, etc) 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 various options in a fair and roboust way. Two real onshore or offshore examples will be reviewed depending on SPE chapter interest. Members will take away a new methodology on how to compare competing factors that influence a completion or well design.
Mr. Dan Gibson is a Senior Completions and Well Integrity engineer with over 35 years of experience. He has worked his way through the oil and gas production stream from Facilities and Production engineering to Completions in assignments across the USA and around the world (Gabon, Congo, Egypt, Scotland, Russia, and Australia). This breadth of experience comes across in the presentation and his ability to deal with different audiences with a wide range of challenges. He has authored or co-authored a number of papers ranging from polymer flood management to ice mechanics and most recently an innovative ICD system. He is one of the most active members of SPE Connect where members can readily contact him with questions.
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. Therefore, reservoir simulations are an appropriate tool to evaluate relative uncertainty but absolute forecasts can be misleading, leading to poor business decisions. As recovery processes increase in complexity, the impact of such decisions may have a major impact on the project viability. A responsible use of reservoir simulations is discussed, addressing both technical users and decision makers. The danger of creating a false confidence in forecasts and the value of simulating complex processes are demonstrated with examples. 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 & white graph of a forecast with realistic uncertainties over a 3-D hologram in colour.
Daniel Yang is a Petroleum Advisor at Shell Canada. Holding a PhD in Geophysics from the Technical University of Berlin, Germany, he dedicated 15 years of his oil-industry career to Enhanced Oil Recovery methods, focussing on thermal recovery and originating from 10 years of research in geothermal energy. Daniel worked at Shell International, Canadian Natural Resources Ltd. and Laricina Energy Ltd. He holds two patents, was recongnized as Subject Matter Expert in Shell, has over 20 publications, recently received an SPE Best Paper Award, and was a guest lecturer at universities in Germany, U.S.A and Canada.
Reservoir simulation is a sophisticated technique of forecasting future recoverable volumes and production rates that is becoming commonplace in the management and development of oil and gas reservoirs, small and large. Calculation and estimation of reserves continues to be a necessary process to properly assess the value and manage the development of an oil and gas producer’s assets. These methods of analysis, while generally done for different purposes, require knowledge and expertise by the analyst (typically a reservoir engineer) to arrive at meaningful and reliable results. Increasingly, the simulation tool is being incorporated into the reserves process. However, as with any reservoir engineering technique, certain precautions must be taken when relying on reservoir simulation as the means for estimating reserves. This discussion highlights some of the important facets one should consider when applying numerical simulation methods to use for, or augment, reserves estimates. The main take away will be an appreciation for the areas to focus on to arrive at meaningful and defendable estimates of reserves that are based on reservoir models.
Dean C. Rietz, P.E., President and member of the board of directors at Ryder Scott Company, has over 30 years of diverse experience in evaluating oil and gas properties, including more than 25 years applying numerical modeling approaches to these evaluations. Prior to his current position, he managed the Ryder Scott Reservoir Simulation Group for approximately 15 years. Before joining Ryder Scott in 1995, Rietz worked at Chevron, Gruy, and Intera. He received a B.S.P.E. degree from the University of Oklahoma and an M.S.P.E. degree from the University of Houston. His past teaching experience includes in-house material balance schools at Chevron and Eclipse user courses at Intera. Currently, Rietz teaches a two-day SPE simulation course and is an adjunct professor of reservoir simulation at the University of Houston. Rietz has published various papers related to reservoir modeling, including its application to reserves reporting. Rietz is a registered professional engineer in Texas and serves on the Petroleum Engineering Advisory Board for the University of Houston.
As we have seen with the advent of the shale oil revolution in the United States, the development of new technology plays an important role in the oil and gas industry. It’s an enabler in reducing capital costs, simplifying production and increasing capacity of new or existing facilities. It can make a marginal project into a profitable development.
Progressing technology, while dealing with significant risk, is a challenge that can be overcome through a technology qualification process. A Technology Qualification Program (TQP) provides a means to identifying the risks and taking the correct steps to mitigate it; not avoid it.
This lecture summarizes the required steps involved in qualifying technology and how to keep track of technology development through the Technology Readiness Level (TRL) ranking system. In addition, some of the pitfalls in executing a TQP program are identified and discussed with emphasis on both component and system testing. Examples are given to illustrate the danger in taking shortcuts when executing the qualification plan.
Data from a recent subsea separation qualification program is presented comparing test results between CFDs, model fluid and actual crude testing at operating conditions. Knowing the limitations of the tools and testing system selected is an important step in closing the gaps identified in the TQP program.
The TRL has evolved at a faster pace and has become more acceptable in the oil and gas industry then the TQP. Nonetheless, continued standardization of both the TQP and TRL is still necessary in order to reduce overall cost of developing technology and allow faster implementation.
Ed Grave Ed Grave graduated from New Jersey Institute of Technology with a Master of Science in 1982. Ed started his career at Lummus working on a number of petrochemical projects, in which in gravitated towards mass transfer and separations. He later joined Mobil Research & Development Company in 1990 as a mass transfer specialist. Today Ed is ExxonMobil’s Upstream Senior Technical Advisor for Fractionation & Separation at ExxonMobil Upstream Research Company in Spring, TX. His team is responsible for research, design, and troubleshooting, for all fractionating & separation systems for the entire ExxonMobil Upstream organization
Ed is recognized for his expertise and as a leader within ExxonMobil in advancing new technology. He also led the effort in designing and qualifying separation system for ultra-deep water, making ExxonMobil ready to meet their future needs.
He initiated and is presently guiding the joint industry Separations Technology Research (STAR) Program on qualifying separation equipment as technical chairman. He also served as vice-chair at SPE’s Separation Technology Technical Section (STTS).
Developing sound energy policies is difficult under the best circumstances. There is a delicate balance between government's need for revenue, modern society's need for energy and the producer's need for profitability to exploit resources. Many factors can affect the results for all interested parties. Good policies require an appreciation for the interactions among oilfield development and operations, costs and prices, government taxes and regulations and many other factors that are often difficult to define accurately. We live in a complex world that acts like a system with many interconnected components. Humans are ill equipped to understand its behavior. We instinctively focus on short term, local issues and simple cause and effect rather than the bigger picture. This reduces the likelihood that we can design effective policies that will work well over the long term for all stakeholders. There are no easy solutions in complex systems. We developed an approach using system models and regret analysis to find flexible and resilient tax policies, in spite of uncertainties, that would provide all parties with fair, profitable solutions – even though none might achieve their maximum goals. It can also measure the relative benefits of existing energy policies and, potentially, help to improve them. These challenges will only become harder in the future and more important for the energy industry. Now is the time to pursue new ways of thinking to solve these problems.
Frank Blaskovich is Vice-President of Blaskovich Services, Inc. in Northern California. He received his B.S. in aerospace engineering from the University of Notre Dame. He has more than 40 years of experience in reservoir engineering and simulation, software development, environmental modeling, and policy analysis. He has worked on energy issues around the world for the largest multi-national energy companies, government agencies and major consulting firms. He has published numerous papers on reservoir simulation and energy policy analysis available in the SPE literature and elsewhere. His work and research activities over the last decade have focused on developing improved energy policies that can benefit all stakeholders fairly.
Collaborative Working helps assets to operate more efficiently and as one team, resulting in higher production, less cost, lower HSE exposure and higher morale. Shell has pursued the Digital Oilfield for the last fifteen years, under the heading of Smart Fields. Collaborative Work Environments (CWEs) were implemented in the majority of assets, live environments now cover over 60% of Shell’s production. The presentation will provide an overview of current Collaborative Work Environments. It will show examples of CWEs in different types of assets, and of the business value achieved. The large scale implementation was achieved through a structured deployment programme, taking assets and projects through a standard design, implementation and embedding approach. To embed and sustain the new ways of working, a focus on the people aspects and change management has been critical. Each project included process design, awareness and training sessions and establishing coaches, support and continuous improvement.
Frans van den Berg is currently an independent consultant in the design of Digital Oilfields and Collaborative Work Environments. He has worked 32 years in Shell, lastly in its global Smart Fields or Digital Oilfield program in the technology organisation in the Netherlands. There he led the global implementation of Collaborative Work Environments in Shell. He has held various positions as a petroleum engineer, head of petrohysics and asset development leader in operational roles and in global technology deployment. He worked ten years in Malaysia and Thailand. Frans has a PhD and a Master in Physics from Leiden University in the Netherlands. He has been involved in the organisation of the SPE Intelligent Energy and Digital Energy Conferences since 2008.
Seismic attributes are being used more and more often in the reservoir characterization and interpretation processes. The new software and computer’s development allows today to generate a large number of surface and volume attributes. They proved to be very useful for the facies and reservoir properties distribution in the geological models, helping to improve their quality in the areas between the wells and areas without wells. The seismic attributes can help to better understand the stratigraphic and structural features, the sedimentation processes, lithology variations, etc. By improving the static geological models, the dynamic models are also improved, helping to better understand the reservoirs’ behavior during exploitation. As a result, the estimation of the recoverable hydrocarbon volumes becomes more reliable and the development strategies will become more successful.
Isabela Falk is a Senior Geologist, currently the Subsurface Team Leader in a Schlumberger P&AM project in Romania. Previously she worked as a Project Geoscientist for Fugro-Jason in Germany and Holland. Prior to that, she worked as a Researcher Geologist in the Romanian National Gas Company: Romgaz. Isabela holds a PhD in Geology from the University Babes-Bolyai from Cluj-Napoca, Romania, since 2008. She has 20 years of experience in the Oil& Gas industry, specialized mostly in geological modeling, but is experienced also in seismic inversion. She made several scientific presentations in internal and international conferences and is a member of SPE, SEG and EAGE.
Heavy Oil recovery traditionally starts with depletion drive and (natural) waterdrive with very low recoveries as a result. As EOR technique, steam injection has been matured since the 1950s using CSS (cyclic steam stimulation), steam drive or steam flooding, and SAGD (steam assisted gravity drainage). The high energy cost of heating up the oil bearing formation to steam temperature and the associated high CO2 footprint make steam based technology less attractive today and many companies in the industry have been actively trying to find alternatives or improvements. As a result there are now many more energy efficient recovery technologies that can unlock heavy oil resources compared with only 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 steam injection is costly and has a high CO2 footprint
Johan van Dorp holds an MSc in Experimental Physics from Utrecht University and joined Shell in 1981. He has served on several international assignments, mainly in petroleum and reservoir engineering roles. He recently led the extra heavy-oil research team at the Shell Technology Centre in Calgary, focusing on improved in-situ heavy-oil recovery technologies. Van Dorp also was Shell Group Principal Technical Expert in Thermal EOR and has been involved with most thermal projects in Shell throughout the world, including in California, Oman, the Netherlands, and Canada. He retired from Shell after more than 35 years in Oct 2016. Van Dorp (co-)authored 13 SPE papers on diverse subjects.
Drilling systems automation is the real-time reliance on digital technology in creating a wellbore. It encompasses downhole tools and systems, surface drilling equipment, remote monitoring and the use of models and simulations while drilling. While its scope is large, its potential benefits are impressive, among them: fewer workers exposed to rig-floor hazards, the ability to realize repeatable performance drilling, and lower drilling risk. While drilling systems automation includes new drilling technology, it is most importantly a collaborative infrastructure for performance drilling. In 2008, a small group of engineers and scientists attending an SPE conference noted that automation was becoming a key topic in drilling and they formed a technical section to investigate it further. By 2015, the group reached a membership of sixteen hundred as the technology rapidly gaining acceptance. Why so much interest? The benefits and promises of an automated approach to drilling address the safety and fundamental economics of drilling. What will it take? 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 understanding and a fear of automation. When will it happen? It is happening now. Digital technologies are transforming 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 his 40 years in the oil industry, he has participated in exploratory drilling operations -- primarily in remote areas of South America -- and in various positions in drilling research and development. His focus has been on exploration and drilling: starting with geology, through geomechanics, drilling modeling, to drilling dynamics and drilling systems automation. He has published about 40 papers, and has more than 25 granted patents. He is the Chairman of the SPE Drilling Systems Automation Technical Section (2014 and 2015), and a member of the Drilling Systems Automation Roadmap initiative. He is a member of the JPT editorial committee.
Adoption of the applied surface-backpressure types of managed 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 towards an automated MPD choke manifold (with a high-resolution mass flow meter) that aside from regulating backpressure also increases sensitivity and reduces reaction time to kicks, losses, and other unwanted drilling events. This integration of MPD equipment into floating drilling rigs to provide them with MPD capabilities, including the capacity to perform pressurized mud cap drilling (PMCD) and riser gas mitigation (RGM), has produced improvements not only in drillability and efficiency, but most importantly in process safety. Case histories on how MPD has performed will be presented on the following: • allowed drilling to reach target depth in rank wildcat deepwater wells that have formations prone to severe circulation losses and narrow mud weight windows; • increased drilling efficiency by minimizing non-productive time associated with downhole pressure-related problems and by allowing for the setting of deeper casing seats; • enhanced operational and process safety by allowing for immediate detection of kicks, losses and other critical downhole events. • provided riser gas mitigation capabilities that can detect a gas influx once it enters the drilling fluid stream, and not after it has already broken out above the rig blow-out preventers (BOPs).
Julmar Shaun Sadicon Toralde is the Global Champion for Deepwater Managed Pressure Drilling (MPD), Downhole Deployment Valve (DDV) and SteadyState Continuous Flow System technologies, based in Houston, Texas, USA. He helped pioneer deepwater MPD deployment on a dynamically positioned drillship in 2010 and is actively involved in major deepwater MPD rig integration projects globally. Shaun is from the Philippines and holds a Geothermal Engineering degree from Negros Oriental State University, where he taught and conducted research on energy engineering. He previously held various field and office management positions with Weatherford in the Asia Pacific region. He has 50 technical papers / trade articles and various MPD training courses to his name.
Integrated reservoir modelling (IRM) is a best practice in the Upstream industry applied throughout all life cycles stages of oil and gas projects aiming at characterisation of subsurface reservoirs and optimisation of field development phases. In this respect, carbonate and clastic reservoirs are different in a range of aspects which will be highlighted. During the past 25 years, major steps in technology development have proven the importance of IRM as a key subsurface contributor to Upstream projects. A brief history of IRM through time will be provided using carbonate examples from exploration, development up to recent learnings around unconventional hydrocarbon trapping. More importantly, these industry showcases will be used to introduce present-day challenges around IRM in the Upstream business. Despite the significant progress in modelling technologies, root causes for disappointing results of such studies are limitations in software tools and workflows together with the lack of integration. This often causes poor project delivery. Such pitfalls within existing practices in the Upstream industry will be discussed highlighting that tools only are not able to assure success in subsurface reservoir characterisation projects. Finally, an outlook into the future of hydrocarbon development planning and IRM will be provided. Ultimately, end-to-end integration in Upstream project workflows requires focus on associated business decisions, scaling of models and scenario management supported by content and context based data management as well as capabilities around fast iterative feedback loops. Only the combined improvements around tools, processes and people will maximise value for Upstream project delivery.
Jürgen Grötsch is currently Global Learning Advisor Geology at Shell responsible for design and deployment of advanced training programs. In this position, his focus areas are integration and building capabilities around decision based subsurface modelling for muilti-disciplinary teams which he was involved with for the past 25 years in various assignments within Shell Production and Exploration ventures around the world. Jürgen holds a Ph.D. in carbonate sedimentology and has authored and co-authored numerous publications and books. He is known as keynote lecturer from international geoscience conferences and, since 2009, as visiting lecturer at the GeoZentrum of the Universität Erlangen-Nürnberg in Germany. Currently, he is Vice-President of the German Geological Society (DGGV).
We are all familiar with the production systems through which reservoir fluids flow to reach our processing facilities. This is a journey characterized by complex multiphase flow phenomena that govern pressure and temperature changes along the way. A monumental amount of research and development work has been invested towards better understanding multiphase flow behavior over the past fifty years. Yet, many challenges remain as we strive to optimize ever more 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? This lecture will discuss key concepts of multiphase flow leading to the current “state-of-the-art” models used today. Looking towards the future, the science must be advanced to address areas of greatest uncertainty and align with trends in field development strategies. Recommendations will be presented covering the top 5 areas of research necessary for these purposes. The economic impact of multiphase operations will be illustrated using two examples that provide insight towards maximizing asset value.
Mack Shippen is a Principal Engineer with Schlumberger in Houston, where he is responsible for the global business of the PIPESIM multiphase flow simulation software. He has extensive experience in well and network simulation studies, ranging from flow assurance to dynamic coupling of reservoir and surface simulation models. He 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 modelling.
Microfracturing is an excellent method of obtaining direct stress measurements, not only in shales, but in conventional reservoirs as well. Recent advances have shown that microfracturing 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 then by conducting a few injection and shut-in cycles, extend the fracture beyond the influence of the wellbore. Results show that direct stress measurements can be successfully acquired at multiple intervals in a few hours and the vertical scale nearly corresponds to electric log resolution. Therefore, microfracture testing (generally performed in a pilot / vertical well) is an appropriate choice for calibrating log derived geomechanical models and obtaining a complete, accurate, and precise vertical stress profile. This talk describes the microfracturing process and presents several examples that led to increased hydrocarbon recovery by efficient stimulation and/or completion design. Case studies presented range from optimizing hydraulic fracturing in unconventionals, determining safe waterflood injection rates in brownfields, and improving perforation placement in ultra deepwater reservoirs.
Mayank Malik is the Global Formation Testing Expert in Chevron's Energy Technology Company and is a champion for advancing research on microfracturing. He holds a B.S. in Mechanical Engineering from Delhi College of Engineering (India), MS in Mechanical Engineering from University of Toronto (Canada), and Ph.D. in Petroleum Engineering from The University of Texas at Austin (USA). Malik has authored numerous papers on petrophysics, formation testing, and microfracturing. He is currently serving on the SPE ATCE Formation Evaluation committee and is also the Chairman for SPWLA Formation Testing Special Interest Group.
Much is now made about “Stress Shadows” and their impact on hydraulic fracturing - particularly in multi-stage horizontal laterals commonly used in Unconventionals. Unfortunately, there is no standard definition of Stress Shadows and, as a result, there is much confusion over what they are and aren’t, and, most importantly, why they can have a significant impact on hydraulic fracturing operations. The goal of this presentation will be 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. As hydraulic fracture propagation is often controlled by the stress field, Stress Shadows may change the propagation path for subsequent hydraulic fractures or, as seen in cluster fracturing, propagation may be impeded completely. The presence of natural fractures and weakness planes can also affect, and be affected by, Stress Shadows. At the hydraulic fracture tip, shear stresses are generated that offer the potential to shear and open closed natural fractures and weak planes – and if opened, it may be possible to stimulate them. Equally important, behind the hydraulic fracture tip Stress Shadows increase the magnitude of all three principal stresses, which tends to close weakness planes making them more difficult to stimulate. Because of these effects and others, understanding and designing for the impact of Stress Shadows is often critical for stimulation optimization.
Dr. Neal Nagel is currently Chief Engineer for OilField Geomechanics and has nearly 30 years of industry experience. He is a well-known expert in the geomechanics of Unconventionals and has given many invited SPE, AAPG, HGS, SEG, and SPWLA presentations. Nagel has also authored or coauthored more than 50 technical papers, with 20+ related to Unconventionals, including a keynote presentation at the 2014 SPE HFTC. He is a past SPE Distinguished Lecturer, was chief editor of the 2010 SPE Monograph on Solids Injection, has served on the SPE Drilling and Completions Committee, and also been a local SPE section officer.
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 unrepresentative rate-time profiles and recoveries over-stated by as much as 50%. These intolerable errors result from common, but incorrect, assumptions in constructing type well production profiles, and the selection and weighting of analog wells. Literature related to constructing type wells is sparse and incomplete. This lecture will fill that gap and lead participants to informed decisions for best practices in type well construction. Hind casting examples show that only small errors in recovery result when the type well construction combines historical and predicted production rates. This improvement results 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 recommended methodology incorporates aggregation and choosing different uncertain parameters. Parameter choice is important 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. Type well construction methods are common, but they have errors that are difficult to detect. Evaluators are likely using type wells for financial analysis, facility design, cash flow prediction, reserve estimation and debt financing without knowledge of the inaccuracies and options to improve accuracy.
Randy Freeborn is a subject matter expert in the field of empirical forecasting, type wells and related technology. Currently, he is Chief Research Engineer at Energy Navigator where he is responsible for identifying and inventing engineering technology for inclusion in the company’s reserve management software. He has been a professional 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 meetings. He has given guest lectures at the University of Houston and Texas A&M, and has been called as an expert witness.
The oil and gas industry places great reliance on layers-of-defenses, or barrier thinking, to protect against process safety 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 supporting 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 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 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. The presentation sets out challenges organizations can use to ensure the human defenses they rely on are as robust and reliable as they reasonably can be.
Ron McLeod holds a BSc in Psychology, an MSc in Ergonomics and a Ph.D. in Engineering and Applied Science and is Honorary Professor of Engineering Psychology at Heriot-Watt University. He has more than 30 years experience as a Human Factors specialists and was Shell’s Global Discipline Lead for Human Factors until March 2014. He has been active in organisations including the UK National Advisory Committee on Human Factors, the Process Safety Leadership Group, as well as the IOGP, SPE and CIEHF. He has published in scientific journals and has authored or contributed to numerous technical standards and best-practice guides. His first book, “Designing for Human Reliability: Human Factors Engineering in the Oil, Gas and Process Industries” was published by Elsevier in 2015.
Modern oil and gas field management is increasingly reliant on detailed and precise 3D reservoir characterisation, and timely areal monitoring. 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 properties of seismic wavefields to enhance surface-seismic imaging. With the advent of new, operationally-efficient very large wireline receiver arrays; fiber-optic recording using Distributed Acoustic Sensing (DAS); the crosswell seismic reflection technique, and advanced seismic imaging algorithms such as Reverse Time Migration, a new wave of borehole seismic technologies is revolutionizing 3D seismic reservoir characterization and on-demand reservoir surveillance. New borehole seismic technologies are providing deeper insights into static reservoir architecture and properties, and into dynamic reservoir performance for conventional water-flood production, EOR, and CO2 sequestration – in deepwater, unconventional, full-field, and low-footprint environments. This lecture will begin by illustrating the wide range of borehole seismic solutions 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 development and management. The lecture will then focus on DAS, explaining how the technique works; its capability to deliver conventional borehole seismic solutions (with key advantages over geophones); then describing DAS’s dramatic impact on field monitoring applications and business-critical decisions. New and enhanced borehole seismic techniques – especially with DAS time-lapse monitoring – are ready to deliver critical reservoir management solutions for your fields.
Steve Morice holds a PhD in Geophysics from Cambridge University, and is a Lead Geophysicist and Shell's global focal-point for well-to-seismic interpretation. With 20 years of experience in the international oil and gas industry, Steve has contributed to the fields of surface- and borehole-seismic survey design, acquisition technologies, processing/imaging techniques, and geophysical interpretation - with particular emphasis on the integration of surface- and borehole data for field development and production optimization. Steve is an author and co-author of numerous technical publications and two patents.
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 OPEX may include increased water production, solids handling and the need for relatively higher compression requirements for gas lift. In order to maintain productivity and profitability, an effective holistic engineering approach to optimizing the process surface facilities must be utilized. The challenges of Optimizing Mature Field Production are: 1. Reservoir understanding with potential definition of additional reserves 2. Complete re-appraisal of the operability issues in the production facilities 3. Develop confidence to invest to optimize the process handling capabilities and capacity 4. Low CAPEX simplification of the surface facilities infrastructure to meet challenges 5. An implementation plan that recognizes the ‘Brownfield’ complexities 6. Selection of suitable optimum technology, configuration and training 7. Optimum upgrade plan of the facilities with minimum production losses Successful operation of mature fields and their surface facilities requires successful change management to the new operating strategy. Using a holistic approach can maximize the full potential of mature processing facilities at a manageable CAPEX and OPEX.
Dr. Wally Georgie Dr. Wally Georgie has a B.Sc degree in Chemistry, M.Sc in Polymer Technology, M.Sc in Safety Engineering and PhD in Applied Chemistry with training courses in oil and gas process engineering, production, reservoir and corrosion engineering. He has worked for over 37 years in different areas of oil and gas production facilities, including corrosion control, flow assurance, fluid separation, separator design, gas handling and produced water. He started his career in oil and gas services sector in 1978 based in the UK and working globally with different production issues then joined Statoil as senior staff engineer and later as technical advisor in the Norwegian sector of the North Sea. Working as part of operation team on oil and gas production facilities key focus areas included optimization, operation trouble-shooting, de-bottlenecking, oil water separation, slug handling, process verification, and myriad other fluid and gas handling issues. He then started working in March 1999 as a consultant globally both offshore and onshore, conventional and unconventional in the area of separation trouble shooting, operation assurance, produced water management, gas handling problems, flow assurance, system integrities and production chemistry, with emphasis in dealing with mature facilities worldwide.
Perforating is a key part in any well completion, being the link between wellbore and reservoir rock. Most think of perforating as being the act of running guns loaded with shaped charges into a well on wireline or tubing and blasting holes as deep as possible into the formation. However, techniques and models have recently evolved that clearly show that the focus should be on perforating for productivity, rather than perforating for penetration. The presentation leads the audience through the research, experiments and models that show how, today, we can maximize reservoir potential through a perforated completion. It highlights the importance of not just penetration, but also shot density and perforation clean up, as well as the need to bring the well on production without damaging new perforations. The one idea I would like the members to take away from this lecture is that they should take care of how they perforate their wells and use the techniques available or risk losing thousands of barrels of production. These techniques apply to new wells, old wells and also help delay unwanted events such as production below bubble point or condensate banking. So not only wells should produce better, but they should also flow for longer without intervention. (Note that this presentation can be tailored for specific local requirements such as "Perforating for Fracturing" or "Perforating Carbonates".
Andy Martin is a Technical Advisor of Perforating for Schlumberger having joined the company in 1979 as a field engineer. His career has taken him through operations, teaching cased hole services and technical writing. From 1996 to 2000 Andy worked at Rosharon, Texas Engineering Facility where perforating systems are developed, shaped charges manufactured and perforating research conducted for Schlumberger. Since then he has moved back to the UK and has been involved in all aspects of perforating and regularly presents and teaches on the topic.
He is a member of SPE, SPWLA and IExE and is a Schlumberger Advisor. Andy graduated from Oxford University obtaining an MA in Engineering Science.
Uncertainty assessment using reservoir simulation models for green- and brown-field situations has become a common practice. While capturing uncertainties in forecasts is required in all situations, developing multiple history-matched models is also an important goal for brownfield situations. Objective of this talk is to provide systematic and practical guidelines for uncertainty assessment work using reservoir simulation models.
This talk discusses steps involved in any uncertainty assessment including selection of uncertain parameters and their ranges, practical experimental design methods, appropriate response or tracking functions (or variables), and data analysis techniques. Roles of lessons learnt from a base-case history-match exercise for a brownfield situation as well as earth modeling/ petroleum engineering knowledge in setting up appropriate parameters and ranges are emphasized. Guidelines are provided to judge “quality of history match” based on prudent interpretation of response or tracking functions/variables. A Monte Carlo simulation-based methodology to develop multiple history-matched models for brownfield situations is presented in detail including practical tips on problem setup and analysis of results. Unique nature of uncertainties related to forecasting situations is discussed with an emphasis on a need to engage all operational and facilities personnel to develop adequate forecast problem description and economic success metrics.
Guidelines presented in this talk are illustrated using a case study example. Practical tips presented in this talk would be of use to all reservoir simulation engineers carrying out uncertainty assessments and always remember one thing - no matter how careful we are, we cannot assess the impact of unidentified uncertainty.
Anil Ambastha has 26 years of experience in various facets of oil and gas reservoir engineering, including applied reservoir simulation, pressure transient analysis, and thermal recovery, since his Ph.D. in petroleum engineering from Stanford University. He has worked in 6 countries and currently serves as "Reservoir Simulation Unit Lead" at Chevron Nigeria Limited. He also served as an Executive Editor of SPE Reservoir Evaluation and Engineering journal (Reservoir Engineering side) from 2008-2011. He is a winner of three SPE International Awards (Lester Uren Technical Excellence, Distinguished Member, and Distinguished Service), seven "Outstanding Technical Editor" Awards, and "A Peer Apart" Award.
First-Ever Comprehensive Environmental Characterization of Hydraulic Fracturing for Shale Oil and Gas Production
The well completion process of high volume hydraulic fracturing has become a touchstone for opposition to the development of oil and gas resources from shale source rocks. Although the development of shale gas and oil has brought substantial economic, geopolitical, and climate change benefits to the United States, hydraulic fracturing has displaced global climate change as the most controversial environmental policy issue. As other countries evaluate development of shale oil and gas, these same environmental concerns are available on the internet and media sources. Without data, the concerns become a substantial hindrance to acceptance of shale gas development.
This study presents the first-ever peer-reviewed study that quantifies the effects of two specific high-volume hydraulic fracturing jobs to 14 different environmental resource categories. The objective was to provide factual information supported by a high quality dataset to guide policy making. None of the measurements detected a change due to hydraulic fracturing, including microseismic effects, ground motion and induced seismicity, water quality, methane migration, community health, well integrity, fracture containment to the target zone, and others. The hydraulic fracturing occurred in the center of Los Angeles, California, at the largest urban oil field in the US. The level of community and regional concern, the breadth of the study, and many of the results are applicable to other shale oil and gas areas worldwide. The results provide the first dataset that addresses the range of concerns directly, and finds no adverse effects to any of the environmental resource categories.
Dr. Dan Tormey is an expert in energy and water. He works with the environmental aspects of all types of energy development, with an emphasis on oil and gas, including hydraulic fracturing and produced water management, pipelines, LNG terminals, refineries and retail facilities. He has conducted important assignments in onshore, offshore, nearshore, estuarine, riverine and glacial environments. Dan has worked throughout the US, Australia, Indonesia, Italy, Chile, Ecuador, Colombia, Venezuela, Brazil, Senegal, South Africa, Armenia and the Republic of Georgia. He has a Ph.D. in Geology and Geochemistry from MIT, and a B.S. in Civil Engineering and Geology from Stanford.
Unconventional Reservoirs require a new petrophysical paradigm and must go “beyond volumetrics.” Efficient unconventional resource appraisal should consider not only the static (storage) and dynamic (flow) properties within the context of the petroleum system and the current day pore geometry and fluid saturation distribution, but also the geomechanical stress regime and its implications for efficient completion design and reservoir performance prediction. Reservoirs with high potential for deliverability should be targeted for development; these zones will dominate well and field performance. The effective application of integrated subsurface and completion workflows leads to improved capital efficiency and well performance through increased well potential, increased ultimate recovery, and reduced costs.
David Spain is a Senior Advisor for Unconventional Gas Petrophysics in the BP Upstream Technology Group in Houston, Texas, where he leads the Geo-Engineered Completion Optimization Project. David has over 30 years experience in research and development, resource appraisal, field development, and integrated reservoir management across the globe. David obtained his graduate degree in Geology from Vanderbilt University in 1982; he attended the Amoco Petrophysics Training Program XXII and has published numerous papers on shale evaluation, tight gas reservoirs, and integrated petrophysical solutions.
The most important aspect in wellbore construction is creating and maintaining wellbore integrity and zonal isolation. The potential of fresh water contamination has captured the attention of the public and media. Cross flow between productive intervals or salt water zones can result in environmental and legal challenges as well as lost production. The number of wells developing annular pressure over time has become a concern and expense for operators. The design and placement of a competent cement seal in the annulus is critical when addressing these issues.
Laboratory testing of cement for use as a physical barrier in wellbore construction has been performed by our industry since the early 1900’s. This Presentation describes how the testing has progressed from Code 32, the first API code, to the present day ISO and API guidelines. The current testing methodology detailed in these guidelines is examined and compared to the actual forces cement is exposed to in the wellbore. Four tests are examined in detail; Thickening Time, Fluid Loss, Compressive Strength and Tensile Strength. The significance of tensile strength is presented.
Some of the traps that can be made by relying on standardized testing are exposed. New developments in cement testing to overcome these issues are presented. Recommendations are then made for testing beyond the standard ISO tests.
The audience should gain a better understanding of what they need cement to do and the laboratory tests required to make sure it does.
Don Purvis is currently a Senior Technical Consultant for Marathon Oil Company. He advises and provides strategies for the Drilling and Completion asset teams within Marathon. Prior to this role he was the US Vice President for Technical Services for Calfrac. In that role he was responsible for the engineering efforts related to Fracturing and Cementing in the US. Prior to Calfrac, Don was the Rocky Mountain Region Technical Manager for the Pressure Pumping division of Baker Hughes. He has 35 years of engineering experience in the oil industry. His previous positions include Engineering Training Manager, Mid-Continent Technical Manager, Research Scientist, and Technical Consultant. He has done extensive research in cement flow dynamics and testing methodology. He has authored 12 technical papers, and several technical journal articles. Don holds two process patents for completion strategies. Don and his wife reside north of Houston Texas and have two grown sons.
The petroleum industry has underperformed for decades because of project evaluation methods that do not fully account for uncertainty. Chronic biases, particularly overconfidence and optimism, persist because there has been little emphasis in the petroleum literature on the true cost of underestimating uncertainty and on how to quantify uncertainty reliably.
In this presentation I will present the results of recent work assessing the monetary impact of chronic overconfidence and optimism on portfolio performance. For moderate and typical amounts of overconfidence and optimism, expected disappointment (estimated NPV minus actual realized NPV) was 30-35% of estimated NPV for the industry portfolios and optimization cases analyzed. Significantly greater disappointments have actually been experienced in industry.
Decision making will be optimal in the long run only when probabilistic forecasts are well calibrated - P10s are true P10s, P90s are true P90s, and so forth. Changing corporate culture to consistently produce well-calibrated probabilistic forecasts will require education on the importance of lookbacks and calibration, as well as changes in business processes and incentive structures. Reliable assessment of uncertainty will add value to the bottom line, and has the potential to significantly improve company and industry financial performance.
Dr. Duane A. McVay is the Rob L. Adams ’40 Professor in the Department of Petroleum Engineering at Texas A&M University. He is a Distinguished Member of SPE. His primary research focus is on uncertainty quantification, particularly in the context of production forecasting and reserves estimation in oil and gas reservoirs. He joined Texas A&M in 1999, after spending 16 years with S.A. Holditch & Associates, a petroleum engineering consulting firm. He received B.S., M.S. and Ph.D. degrees in Petroleum Engineering from Texas A&M University.
Increasing Production with Better Well Placement in Unconventional Shale Reservoirs - Challenges and Solutions
The idea that the stimulation process "will take care of the geology" in unconventional reservoirs is proving false.
Unconventional reservoirs are often regarded as resource plays with little demand for reservoir analysis beyond simple geosteering techniques during the development campaign. This leads to the common practice of stimulating wells with equally spaced stages and treating all the stages exactly the same, with no regard to the nature of the rock being treated. As a result, production can vary from each stage, with some stages either not contributing or doing poorly.
Clearly, the stimulation process alone cannot mitigate the impact of geology in unconventional reservoirs; however, mechanisms do exist for improving results in these reservoirs. Mapping the distribution of geomechanical properties for optimal stimulation is one example of unconventional thinking that can be applied. The practice of "steering to brittleness" or similar techniques can have a direct impact beyond simple well placement. Given a map of geomechanical properties along the wellbore, completion engineers can optimize the position of plugs or packers, and stimulation engineers can fine tune the design of the treatment applied to the rock. By re-establishing the link between production and geology, these methods can decrease the exploitation costs of unconventional reservoirs.
Jason Pitcher is an independent consultant. Based in Houston, TX, he works with clients in Exploration and Production, Oilfield Service companies, Oilfield Equipment Manufacturers and Private Equity groups as a technical advisor. He combines technical expertise with a solutions mindset enabling clients across the Upstream value chain to deliver on asset performance objectives.
Jason is an accomplished advisor to the E&P industry, with a personal focus on Unconventional resource exploitation and well placement. He has over 20 years of experience in the E&P space, having worked in multiple areas of subsurface and surface technology and operations.
Jason received his Bachelors of Science in Geology from the University of Derby and his Masters of Science in Mineral Exploration from Imperial College in London. He has co-authored over 30 papers and articles on topics including Unconventional Exploration and Development, LWD tools, Petrophysics and Geosteering. He is a two-time Distinguished Lecturer for the SPE, serving in 2012-2013 and 2015-2016.
On 20 April 2010, the Macondo blowout in the U.S. Gulf of Mexico killed 11 men, burned and sank the Deepwater Horizon drilling rig, and devastated the Gulf. Investigative authorities queried mechanical systems, operating decisions, corporate cultures, safety procedures, and testimony by survivors, academics, experts, and executives. Meanwhile, industry personnel need succinct, non-litigious, technical answers to fundamental questions about the cause of the blowout for application to future projects. Such answers define the specific mechanics, actions, and decisions on the rig that collectively opened a pathway into a cased-and-cemented deep-water wellbore and allowed hydrocarbons to flow unobserved from a high-pressure reservoir to eventually erupt over the derrick and continue even after the blowout preventers were closed.
To unravel the cause of the blowout, data during the well's final hours are assessed and defined using petroleum-engineering fundamentals, including wellbore mechanics, hydrodynamics, inflow performance, fluid properties, well-control principles, etc. The chain of events thus revealed includes forming an annulus-to-wellbore leak, exacerbating the leak, testing and declaring the well secure, causing the well to flow, and allowing the well to flow until too late, even for the blowout preventers. The technical assessment leads to conclusions that define those factors that contributed to the blowout, as well as to those that caused the blowout.
From the presentation, SPE members and a wider audience from across the industry and beyond will see by example the necessity and importance of applying petroleum-engineering and process-management fundamentals to day-to-day drilling work, in real time, both in the office and on the rig. From the Macondo assessment, a process-interruption protocol is defined, which can be applied to wells around the world, whether deep or shallow, onshore or offshore.
J. A. (John) Turley taught petroleum engineering at Marietta College before joining Marathon Oil Company, where he served as Gulf Coast drilling manager, U.K. operations manager, manager worldwide drilling, and vice president engineering and technology. He holds a professional degree in petroleum engineering from Colorado School of Mines, an MS in ocean engineering from University of Miami, and an executive management degree from Harvard University. Post-retirement, he independently researched the 2010 Macondo blowout and published "THE SIMPLE TRUTH"—a facts-based tome in which he examines the engineering causes of the Macondo blowout aboard the Deepwater Horizon. His first SPE paper (6022), "A Risk Analysis of Transition Zone Drilling," was published in 1976. In 2014, he published SPE-167970-MS, "An Engineering Look at the Cause of the 2010 Macondo Blowout." Turley, a member of SPE's Legion of Honor, has served SPE in academic and conference capacities, but most enjoyed chairing SPE's education and accreditation committee.
Economic development of low permeability, unconventional reservoirs has necessitated the development of leading edge horizontal drilling, completion, and stimulation techniques. As early as the 1980's, bold statements were made indicating that there were little advances in horizontal drilling technologies required, but that significant improvements in stimulation and completion technologies were necessary.
This presentation starts by asking the audience to consider two questions:
- Does completion technology lag behind drilling technology? and
- Can we drill longer wells than we can effectively complete/stimulate?
For the "resource plays" of today, it is recognized that the challenge for completion technologies to keep pace with drilling advances are different than in the past. Economic, supply chain, logistics and environmental challenges may present the largest hurdles. Today's challenges and limitations are discussed along with innovation solutions currently being applied.
The presentation wraps up by posing the future question: Are completion engineers prepared to effectively stimulate and complete the "3-mile lateral"? What will future field developments look like and what new completion technologies are required? Can we bridge the gap between drilling and completion in unconventional reservoirs?
Mary Van Domelen is an Engineering Advisor with Continental Resources. She holds a BS degree in Chemical Enginering and is a licensed engineer. She has 30 years of experience in research and practical application of well completions. Mary started her career with Halliburton and has worked in the USA, Europe and Africa. Prior to Continental, she worked for Maersk Oil and Chesapeake in horizontal drilling and completion operations. She has co-authored more than 30 papers and holds several patents. Mary plays an active role in the SPE by participating in organizing committees for conferences, applied technology workshops, and forums.
While many remote parts of the world and North America are awash with natural gas, Europe, South America and the vibrant economies of the East cannot get enough of the clean-burning, environmentally friendly fuel. The problem is transporting this compressible fluid long distances, across major bodies of water. For markets greater than 1,500 miles, liquefied natural gas (LNG) has proved to be the most economic option. By refrigerating natural gas (primarily methane) to -260ºF (-162ºC), thereby shrinking its volume by 600:1, LNG can be transported in large insulated cryogenic tankers at reasonable cost.
Natural gas liquefaction is a series of refrigeration systems similar to the air conditioning system in our homes, simply consisting of a compressor, condenser and evaporator to chill and condense the gas. The difference is in the scale and magnitude of the refrigeration. In contrast to the home system, a typical single-train LNG plant costs billions of dollars and consume 6-8% of the inlet gas as fuel. Since many of the impurities (water vapor, carbon dioxide, hydrogen sulfide, etc.) and heavier hydrocarbon compounds in natural gas would freeze at LNG temperatures, they must first be removed, and disposed or marketed as separate products.
This paper will provide an overview of LNG liquefaction facilities, from inlet gas receiving to LNG storage and loading. However, the focus is on the liquefaction process and equipment. Differences among the commercially available liquefaction processes (cascade, single mixed refrigerant, propane-pre-cooled mixed refrigerant, double mixed refrigerant, nitrogen, etc.) will be discussed. The aim is to provide SPE members with a clear understanding of the technologies, equipment and process choices required for a successful LNG project.
Michael Choi is a recent retiree. Prior to March 2015, he was a Process Engineering Fellow in ConocoPhillips’ Global Production Department located in Houston, Texas. His specialties are production facilities, sour gas treating and LNG. He was the lead process design engineer for CoP’s Qatargas3 LNG project. Prior to joining Conoco in 1985, Michael worked in various engineering capacities with El Paso Natural Gas, Aminoil and Getty Oil/Texaco. His work has led to a number of SPE publications and six US patents for separator design, emissions control system for glycol dehydrators and subsea processing and storage systems. Michael has been active in SPE as member of the PF&C Committee, program chairman and member of the ATCE and other international conferences and forums. He graduated from the University of Southern California in 1974 with a BS degree in chemical engineering.
Michael was an SPE Distinguished Lecturer during the 2012-13 lecture season.
Matrix stimulation treatments in carbonate reservoirs are generally considered low risk. Production increases from these treatments are routine and the advantages of these treatments are perceived to be high. However, many treatments realize only a small fraction of the true well potential. If a more holistic evaluation criterion is used, many treatments would not be considered successful. This lecture will start with a brief introduction to matrix stimulation in carbonates and describe typical design elements. This will be followed by design challenges, such as treatments in long heterogeneous intervals, in fractured reservoirs, and in mature reservoirs. The many variables influencing the treatment design and the challenge in optimizing the design with respect to these will be addressed. The influence of rock type, treatment fluid type, and operating conditions will be discussed. The available technologies for fluid placement will be presented in the context of formation complexity and the length of producing interval. The design workflow proposed will ensure that all variables are addressed systematically.
Dr. Murtaza Ziauddin is an Advisor for Matrix Stimulation and Production Chemistry with Schlumberger in Sugar Land, Texas. He has more than 18 years of production engineering experience. Murtaza Ziauddin has co-authored three SPE books. The lecture will draw on material from his most recent book, "Chemistry for Enhancing Production" as well as from his contributions to the upcoming update to the classical SPE Monograph on Acidizing. He has authored 27 technical papers and holds 14 patents. Murtaza has a BS degree from the University of Houston and a PhD degree from the University of Minnesota, both in chemical engineering.
For oil and gas companies, accelerating the process of assessing reserves is a strategic imperative. Often, core analysis appears to be a bottleneck for achieving this objective. Lab results must not only be accurate, but also quickly available. In some instances, the challenge can be met by simply rethinking the way in which certain well-established things are done. No sophisticated tools are required, just a change of perspective. An example is the compression of the amount of time that elapses between the acquisition of electric logs and the release of their final interpretation. Typically this time is of the order of several months because of the long equilibrium times required during core analysis. This can, however, be reduced to a few days working under non-equilibrium conditions. The instrumentation needed to do this is commonly available. Another example is the estimation of the amount of gas trapped by water influx, a critical parameter that may generate considerable uncertainty in the evaluation of recoverable reserves. By combining centrifuge and NMR measurements, it is possible to produce an exhaustive compilation of SCAL data for log interpretation and reservoir modeling in one day using just one core sample. Again, nothing but conventional instruments are required to do this type of analysis. Real applications are presented to show how these methods work. The "take home" message is that even long-established laboratory practices may have room for improvement and sometimes relatively small changes generate significant benefits.
Nicola Bona is technical leader of the Petroleum Engineering Laboratories at ENI e&p. Besides providing operative support for the characterization and development of oil and gas fields worldwide, he is actively involved in designing equipments and experimental protocols aimed at increasing the accuracy of petrophysical measurements and speeding up their execution. Among other things, Nicola pioneered the use of drill cuttings for reservoir characterization and the use of dielectric measurements to assess rock wettability, as well as new methods for evaluating the electrical response of rock. He developed also innovative techniques for the evaluation of fractured reservoirs, shaly rocks and tight sands which make use of Magnetic Resonance Imaging. Nicola has authored over 30 technical papers and holds two patents. He holds a degree in Plasma Physics from the University of Milan.
Making Better Appraisal & Development Decisions: Using Decision Risk Analysis & Value of Information
Behavioural science suggests that human nature favours decisions that satisfy (good enough is good?), not necessarily those that optimise. Often value is left on the table, particularly when risks & uncertainties are involved. More than fifty years ago an approach was born which helps to overcome this human limitation, namely Decision Risk Analysis (DRA), which helps us to optimise not just survive.
DRA is a structured process involving both facilitation and modelling that helps stakeholders optimise their decision making in the face of risks and uncertainties. Decisions come in all sorts of shapes and sizes and so does the best way to optimise the chosen value measures. This presentation introduced DRA and then focuses on one tool in the armoury known as Value of Information analysis (VOI). VOI is an acronym used by many, but maybe understood by few. The when, why and how of VOI will be explained, so hopefully, by the end of this talk the listeners will expand the ranks of the ‘few’.
If you are facing a number of decisions where outcomes are uncertain and there is an opportunity to acquire additional information which costs money and/or time, then you should consider undertaking a VOI analysis and this talk will be of interest to you.
Pete Naylor has a Physics BSc, a Chemical Engineering PhD and is a Chartered Scientist, a Chartered Engineer and a Fellow of the Institution of Chemical Engineers. He has 30 years of experience in oil & gas and for the past 15 years has led DRA studies to optimise significant investment decisions. He also leads Project Risk Management studies helping managers to achieve their objectives on time and budget. Pete has worked within integrated teams on major decisions including field appraisal and development strategies, refurbishment of facilities and asset integrity management. He has presented widely and has published more than 35 papers.
The unique challenges of hydrocarbon production from shale reservoirs have required operators to take a fresh approach to asset development. Decisions about well placement, geometry, completion, and production are interrelated and must be addressed as part of life cycle planning. Artificial lift systems must be configured for rapidly changing and dynamic production environments. Migration from one lift technology to another is often required for wells that typically experience steep production decline rates. This presentation discusses the unique challenges of unconventional production and presents current production trends supported by field examples. Recommendations for optimizing production from shale and tight reservoirs are presented.
Dr. Rajan Chokshi works as Optimizer for Accutant Solutions of Houston – A training and consulting services provider for production optimization.
In a career spanning over 30 years, Dr. Chokshi has worked on petroleum and software engineering projects globally in the areas of multi-phase flow, artificial lift design, and production optimization in oil and gas industries. He continues to consult and teach professional courses in these areas. His interests are developing and nurturing young talent globally, technology integration and commercialization.
Dr. Chokshi is a Society of Petroleum Engineers’ Distinguished Lecturer for the 2015-2016 year. He also serves on the SPE global committees for training and production awards. Dr. Chokshi holds a Bachelors and a Masters in Chemical Engineering from the Gujarat University and IIT-Kanpur, India; and a Ph.D. in Petroleum Engineering from the University of Tulsa, USA.
The task of identifying key production drivers in unconventional reservoirs remains challenging, even after decades of exploration and production in North America during which tens of thousands of horizontal unconventional wells have been drilled and completed. Tens to hundreds of variables, categorized as reservoir quality, well architecture, completion, stimulation, and production metrics, are involved and there are many different interrelationships among the variables to be considered. Further, formation evaluation is typically minimal and there are unknown variables in the system that can only be guessed at, ignored, or proxied.
The author’s team has combined Geographical Information Systems (GIS) analysis and multivariate analysis using boosted regression trees for improved data mining results as compared to univariate methods. The purpose of this lecture is to discuss key elements of data mining in unconventional reservoirs, in order to raise awareness of cutting-edge statistical tools and methods being brought to bear in the industry. The presentation will provide highlights of real world examples of data mining projects in three different shale plays.
If there were only one idea for audiences to take away from the lecture, it would be that exploiting unconventional reservoirs is a highly complex task with many moving parts and data mining is a needed tool to be applied to better understand the importance of specific well productivity drivers. Another way to say it is that the talk is intended to provide the audience with improved statistical methods for the "statistical" plays so that multi-million dollar decisions can be truly data-driven.
Randy LaFollette is the Director, Applied Reservoir Technology, for Baker Hughes Pressure Pumping. Mr. LaFollette holds a BSc degree in Geological Science from Lehigh University, Bethlehem, Pennsylvania. He has 37 years of experience in the industry. He is active in SPE, and AAPG, aiding with conference organization and presenting on various reservoir, completion / stimulation, and data-mining topics. Mr. LaFollette is a subject matter expert in Geoscience and Petroleum engineering for Baker Hughes and leads a team of experts responsible for structuring and implementing geospatial and data-mining studies of stimulation effectiveness linking reservoir quality, well architecture, well completion, and treatments performed to production results.
The spread of horizontal drilling and multiple-stage fracturing in unconventional reservoirs has revolutionized the oil and gas industry. Because of this revolution, engineers and geoscientists are using ground breaking technologies to optimize field development strategies. “Underground Laboratories” have become the new approach to solving complex problems like landing interval, well spacing, and completion design. These “laboratories” integrate technologies such as fiber optic distributed sensing, offset pressure monitoring, microseismic acquisition, and tracers in multiple neighboring wells.
This lecture will discuss completion design for fiber optic distributed acoustic sensing (DAS) and distributed temperature sensing (DTS) and how this data is incorporated with other advanced monitoring techniques. Real-life examples will be used to demonstrate how these new measurements are used to optimize completion design. Similarly, these integrated measurements are also important to build fracturing and reservoir models which inform landing interval and well spacing. The insight from these Underground Laboratories becomes the foundation for optimizing production, capital allocation, and ultimate recoveries from unconventional reservoirs.
The takeaway from this lecture will be a new understanding of using advanced fracture monitoring to make better decisions for unconventional field development.
Trey Lowe is the Completions Technology Manager at Devon Energy, where he leads a team focused on optimizing completions across the United States. Trey has spent more than 15 years working on completion and production operations in various countries around the globe. After designing and executing complex offshore completions, he began applying this experience to the US unconventional plays. Trey serves on the SPE ATCE Well Completions Program Committee and has authored multiple technical papers on completion and production operations. Prior to joining Devon, he held various field, management, and technical positions with Schlumberger Oilfield Services. During his time at Schlumberger, he was awarded the “Performed by Schlumberger, Chairman’s Award” for advancement of multiphase measurement. Trey has a Bachelor of Science in Chemical Engineering from Oklahoma State University.
Industry has recognized that dynamic reservoir characterization, from wellbore pressure and production behaviors, is a key driver for maximizing the production and recovery of a reservoir. Accurate simulation requires appropriate modeling of the existing heterogeneities in the field. Most of the main fields around the world produce from naturally fractured vuggy reservoirs, where matrix, fracture network, and high vuggy porosity are usually present. Vugs effect on permeability is related to their connectivity and the determination of permeability and porosity in vuggy zones from core measurements are likely to be pessimistic. Also, some fractured reservoirs exhibit a fractal behavior, which describes fractures with different scales, poor fracture connectivity and disorderly spatial distribution. Both fractured vuggy and fractal behavior reservoirs cannot be explained by the conventional dual-porosity model. This lecture addresses different characterization approaches that take into consideration the above descriptions, that include as special case the classic dual-porosity model, and reviews field applications in which these approaches were used in reservoir characterization by using pressure transient and rate data. It also outlines the challenges encountered during characterization of fractured reservoirs and presents a current and future vision for an appropriate dynamic characterization of these reservoirs.
Rodolfo Camacho works as a senior engineer for Pemex E&P. He has more than 30 years of experience in academia and E&P fields. He has developed several well test analysis techniques, and analysis and interpretation methods of production data. He has authored or co-authored more than 100 technical papers on petroleum engineering. He has won several awards including the 2008 Lester Uren Award. He holds a BS degree in geophysical engineering from the University of Mexico and MS and PhD degrees in petroleum engineering from the University of Tulsa.
Optimism in Reservoir Production Forecasting - Impact of Geology, Heterogeneity, Geostatistics, Reservoir Modeling, and Uncertainty
The oil and gas industry uses static and dynamic reservoir models to assess volumetrics and to help evaluate development options via production forecasts. The models are routinely generated using sophisticated software. Elegant geological models are generated without a full understanding the limitations imposed by the data or the underlying stochastic algorithms. Key issues facing reservoir modelers that have been evaluated include use of reasonable semivariogram model parameters (a measure of heterogeneity), model grid size, and model complexity. However, reservoir forecasts tend to be optimistic – a statement not provable with data in the public domain. Yet, conversations at technical meetings, the lack of industry publications highlighting actual forecast accuracy, the development of more detailed reservoir models (presumably to yield better forecasts), all suggest that the industry could improve its reservoir performance forecast accuracy. For example, dynamic models that use larger grid cells yield optimistic forecasts for some recovery processes as compared to forecasts obtained from models built with smaller grid sizes. Also, the use of stochastic earth models and well placement optimization workflows will likely yield optimistic forecasts. Overall, the impact of cell size, model parameters, inadequate use of analog data, and poorly constrained well location optimization may increase forecast optimism by 5-10 recovery factor units or more. Knowing what workflow aspects may contribute to forecast optimism should enable the industry to generate more reliable forecasts and make better use of capital.
Dr. William Meddaugh joined the Midwestern State University in 2013 as the RL Bolin Distinguished Professor of Petroleum Geology. He has 32 years of experience with Chevron including technical project management experience on projects in the United States, Canada, Venezuela, Middle East, West Africa, and Australia. He is a member of the SPE, AAPG, and EAGE and is an Associate Editor for the SPE Reservoir Evaluation and Evaluation Journal. He received a PhD in geology from Harvard in 1983. He has authored or co-authored over 30 peer reviewed and SPE technical papers on forecast optimism, reservoir characterization, and modeling.
Subsurface uncertainty is one of the main challenges in using reservoir models to predict field performance for development and depletion planning purposes. The importance of reliable characterization of subsurface uncertainty and its impact on reservoir performance predictions is increasingly recognized as essential to robust decision making in the upstream industry, which is especially true for large projects in complex geologic settings. However, despite recent advances in reservoir modeling and simulation, reliable quantification of the impact of subsurface uncertainty remains difficult in practice. Many factors lead to this state of affair; technically, a fundamental difficulty is that reservoir heterogeneity at multiple scales may have strong effect on fluid flows. This lecture presents an analysis of the challenge and possible resolutions. Indeed, relying on computing power alone may not address the challenge. Instead, we must look at reservoir modeling and performance prediction holistically, from modeling objectives to appropriate techniques of incorporating reservoir heterogeneity into the models. We present a goal-driven and data-driven approach for reservoir modeling with the theoretical reasoning and numerical evidence behind them, including real field examples. We show that the proposed approach is driven by the practical limitations inherent in numerical approximations of Darcy flow equations as well as how fluid flow responds to reservoir heterogeneity. The one idea that participants of this lecture should take away is that appropriate parameterization of multi-scale reservoir heterogeneity that is tailored to the business questions at hand and available data is essential for addressing the challenge of subsurface uncertainty.
Xiao-Hui Wu joined ExxonMobil Upstream Research Company in 1997. His research experience covers geologic modeling, unstructured gridding, upscaling, reduced order modeling, and uncertainty quantification. He is a Senior Earth Modeling Advisor in the Computational Science Function. Xiao-Hui received his Ph.D. in Mechanical Engineering from the University of Tennessee and worked as a postdoc in Applied Mathematics at Caltech before joining Exxon Mobil. He is a member of SPE and SIAM, a technical editor/reviewer for the SPE Journal, Journal of Computational Physics, and Multiscale Modeling and Simulation. He served on program committees of several conferences, including the Reservoir Simulation Symposium.
Extracting hydrocarbons from subterranean formations is a prolonged operation stretching over several decades. During this period, a bewildering variety of chemical additives are used to address various needs of the oilwell operations. A 2010 estimate puts the projected global annual OFC sales at about $30 billion by the year 2015.
The OFC chemicals must be approved for use and registered by appropriate regulatory agencies of individual countries. Unfortunately, there is no global uniformity in the laws applicable to chemical use in individual countries. Frequently, even within the same country, different agencies of a government can have different requirements that a chemical must meet before they can be approved. This puts a tremendous pressure on OFC suppliers to dedicate resources and efforts to develop chemicals to meet diverse regulations even when they are meant for the same application. It is not uncommon that development of new products and technologies is often not undertaken because of lack of business justification.
It is a fact that all parties involved in hydrocarbon production wish to develop and use only chemicals which are based on sound HSE principles and practices, but differ only in what the HSE data and protocols ought to be for approvals. This talk hopes to bring awareness to the current status of OFC use from HSE perspectives and stimulate a healthy discussion; and puts forth a proposal for consideration aiming for unified global approval requirements for OFC use by all nations based on cradle-to-grave holistic approach that is based on not only HSE compliance, but also on HSE-based best practices from syntheses all the way through production, storage and transportation phases. The talk solicits and urges concept buy-in and united campaign from global organizations connected to hydrocarbon production to globally harmonize testing protocols and approval processes for OFC chemicals.
Primary Technical Discipline: HSSESR
B. R. Reddy has been with Halliburton for 17 years, and is currently Chief Scientific Advisor - Chemist.During this period, he has worked in the areas of Cementing, Conformance, drilling fluids, and long range research covering all areas of Halliburton chemical research. The job responsibilities included new product and processes developments. Some of the new technologies that he has contributed to were recognized with granting of 177 US patents. He has coauthored more than 35 SPE papers.
One of the greatest revolutions in the history of the oil and gas industry has taken place over the past decade. This revolution is the rise of the shale reservoirs. First drilled in the 1820s these reservoirs did not attract serious attention due to their economics until the late 1990s when the Barnett Shale emerged as an industry “game changer”. Numerous other shales rapidly attracted the attention of the industry until today dozens of shales are currently being drilled throughout North America. This revolution is rapidly spreading to many locations throughout the world. Initially these shales were developed using statistical drilling methods in which a large number of horizontal boreholes are drilled throughout the play. Until recently gas prices supported the economics of this approach. But due to their success, an abundance of gas has caused a decrease in gas price and a new economic paradigm has emerged, shale sweet spot drilling. Production from numerous shale plays indicates the existence of these sweet spots. These result from certain geologic conditions, such as increased matrix porosity or TOC, increased micro-fractures and areas with increased brittleness. These reservoir characteristics affect the physical rock properties which, in turn, affect a passing seismic signal. Recent advances in seismic interpretation have demonstrated that these shale reservoir sweet spots can be detected prior to drilling. The ability to locate these sweet spots before drilling significantly impacts the economics associated with these plays. During this presentation a number of these seismic interpretation methodologies will be discussed.
Primary Technical Discipline: RDD
Brian E. Toelle is Adjunct Assistant Professor at West Virginia University and an Advisor in Exploration and Geophysics for Schlumberger. He holds BSc, MS, and PhD degrees in geology and has worked in the oil and gas industry for over 33 years. He has authored/co-author 47 professional papers, posters and presentations, received Saudi Aramco’s Exploration Professional of the Year Award and the "Performed by Schlumberger Award". His expertise includes Exploration Play and Prospect Generation, Shale Reservoir Geology and Geophysics, Field Development Planning, Underground Gas Storage Field Development, Enhanced Oil Recovery Projects, CO2 Sequestration Projects and Seismic-based Fracture Detection methods.
The key message is that the offshore use of CO2 for EOR is in its infancy but with the adoption of CCS to decarbonize fossil-fuelled power generation there is a time critical opportunity to add value to the CCS chain by adopting and maturing offshore CO2 EOR.
The UK has a legally binding target to reduce CO2 emissions by at least 80% by 2050 (compared to 1990). To achieve this, a significant proportion of the UK’s fossil-fuelled power generation is likely to be replaced by new coal and gas-fired power stations equipped with carbon capture. Screening studies have shown that there is technical potential to achieve an incremental recovery in the billions of barrels from CO2 injection in the UK’s offshore oil reservoirs and significant potential in adjacent national blocks. However, there is no experience of injecting anthropogenic CO2 into offshore oil fields so despite the maturity of land-based CO2 EOR, this is a significant new challenge.
As there is a global imperative to reduce CO2 emissions, this opportunity is potentially also available to other countries with fossil-fuelled power generation and an offshore oil industry. The talk will include policy background, plans by utility companies, sources and sinks for CO2, the EOR opportunity, infrastructure requirements, logistics and engineering challenges.
Primary Technical Discipline: MI
David S Hughes is a reservoir engineer with 34 years’ experience. He currently works for Senergy in the UK.
Throughout his career he has specialized in the scientific, technical and engineering aspects of enhanced oil recovery processes including hydrocarbon and CO2 gas injection, chemical and biological processes, and in situ combustion.
David has undertaken design assessments of CO2 EOR projects in offshore and onshore reservoirs and was first involved in such assessments in the 1980s. He is currently undertaking engineering studies related to offshore CO2 storage, EOR & EGR and low salinity water flooding.
David holds a BS Honors degree in Physics from the University of Surrey, UK and was previously a SPE DL in 2008-2009.
There is a need to take a closer look at one aspect of sand control commonly recognized, but seldom addressed; formation fines. How many times are good sand control methods placed in wells only to have the wells make “sand” which really turns out to be “fines”. Several major operating companies are now starting to notice many wells are showing increasing skins over time. Many factors can contribute to Increasing skin over time; however, one of the most often cited causes is formation fines migrating into and becoming trapped in the near wellbore reservoir matrix and/or gravel pack or frac pack. If fines are a major factor, what are the sources of the fines? What factors contribute to the generation of the fines? What kind and how much fines are generated? What controls the production of the fines? What is the impact of any fines on production and downhole equipment? What is the relative importance of these factors? If fines can/do move, it is possible to address potential problems by changing the sand control method, production/injection strategy; i.e., Flux Management, or wellbore architecture to minimize the impact of fines production. Chemical treatment of the near wellbore area is also possible. The presentation discusses a methodical approach to evaluating the potential for fines production, ways to address the issues, and to appraise the overall impact on the life cycle of the well. Case histories are presented to illustrate the impact of fines on production and how it is possible to address problems related to the movement of formation fines.
Primary Technical Discipline: DC
David Underdown is a Research Consultant with Chevron Energy Technology Company in Houston. He holds a PHD in physical chemistry, and has worked in the area sand control and formation damage for over 40 years for Getty Oil Company, Baker Sand Control, ARCO and now Chevron. He is past Chairman of the API Task Force on perforating, Chairman of one of SPE’s Award committees, Chairman of a SPE paper review committee, editor of the SPE Monographs on sand control and completion fluids. He has multiple papers and patents.
As oil demand increases and technology advances deeper carbonate reservoirs are being developed, some off-shore in high water depths such as in Brazil’s Presalt. These reservoirs contain mainly Dolomite/Limestone having porosity variations from microcrystalline to caverns, also natural hairline fractures are encountered due to tectonics becoming double porosity heterogeneous reservoirs.
Depending on reservoir’s tightness and radial damage extent from the construction phase, these reservoirs may require stimulation to initiate production or to be commercial. Carbonate rocks are 100% soluble in HCl that is the standard acid used to stimulate these wells with postive but seldom optimum results. Limited acid penetration and possible formation collapses at the near wellbore caused by rapid acid reaction can impair the full stimulation benefit. The reaction is “mass transfer controlled” affecting radial treatment displacement as wormholes are spontaneously created, that commingled with high acid diffusivity reduce our ability to control acid leak off. Lower permeability and higher temperatures encountered in deeper reservoirs increase the reaction rate; on the other hand the acid dissolving power are limited volumetrically for typical concentrations and higher volumes are required. An optimum stimulation can be obtained by balancing Penetration and Conductivity, so technology has evolved in their search. More efficient, resistant and friendly products and systems have been developed, that are now being used in Horizontal Wells stretching their application. Acid tunneling lateral branches have improved penetration and ‘viscoelastic surfactants’ have improved acid distribution, both noticeable in improved treatment results that are illustrated as case histories in this presentation
Primary Technical Discipline: PO
Gino Di Lullo is a registered engineer and holds a BSEE from UCP-Brazil. After training with DS in Bolivia, he alternated Field, Technical, Marketing and Managerial positions in Middle East, South America, Asia and Africa for Schlumberger, BJ Services, Baker and Superior Energy where he retired in 2013, becoming an Energy Consultant.
Being a multidiscipline engineer has interacted in most related areas of our business aiming to construct wells more productively and cost effectively, as such during his carreer he invented cementing, acidising and fracturing additives, developed design software, authored several patents (including Sandstone Acid and Acid Tunneling) and published over 50 technical papers.
Participated in 3 SPE Formation Damage-Stimulation Forums in Bali and was the Keynote Speaker for the SPE-ATW in Kota Kinabalu. In 2006 organized the first and only Regional SPE- Distinguished Lecture Forum in Rio.
Logging measurements in cased wellbores are almost always more difficult to make and tend to be more sensitive to the logging environment than the equivalent measurements in open hole. While not all openhole measurements are possible in cased wellbores it is possible to make many of our more basic measurements in either open or cased wellbores.
There are numerous reasons for making traditional openhole measurements after casing has been set. Some of these reasons include difficult logging conditions, highly deviated wells where deployment is a problem, or simply avoiding expensive rig time. The increasing numbers of horizontal wells, especially in unconventional reservoirs, has led to a trend where the majority of new horizontal wells are not logged. Logging While Drilling or deployment of wireline tools in long horizontal openhole sections are often not an option due to cost or risk factors associated with deployment. Logging after the well has been cased can offer a greatly reduced risk as well as reduced cost.
The introduction of pulsed neutron capture measurements nearly 50 years ago provided some of the first opportunities to do formation evaluation in cased wellbores [Raymer and Morris, SPWLA Paper G 1964]. Over the years, new cased hole measurements have been introduced to make measurements previously only observed in openhole.
It is not my intention to suggest that logging in cased wellbores provides better data than what can be achieved in openhole. However in many cases it is possible to acquire the necessary data in cased holes to allow for a better completion design. Nowhere is this more useful than in the complex wellbores of today where we often have no formation evaluation data on which to base our completion.
Primary Technical Discipline: RDD
James Hemingway started with Schlumberger in 1980 and has held various petrophysics and engineering positions with Schlumberger since 1982. He has been heavily involved in reservoir monitoring of Enhanced Oil Recovery operations using techniques designed for use in cased wellbores. James holds degrees in chemistry and chemical engineering.
In 1997 he joined the Formation Evaluation department at the Schlumberger Sugar Land Product Center working on the RSTPro* (carbon-oxygen) tool and "Three-Phase Holdup" interpretation techniques. He moved to Paris in 2001 as a new technology advisor and has been based in Houston since 2010 as a Petrophysics Advisor focusing on unconventional resources.
James was a Distinguished Lecturer for the Society of Petrophysicists and Well Log Analysts in 2000-2001 and 2011-2012 on cased hole logging technologies.
Acoustic data are routinely acquired around the world for a variety of uses, but most often for classic applications such as seismic correlation, pore pressure prediction, porosity, and hydrocarbon identification. However, hidden in the very same waveform data acquired for these purposes is a wealth of additional information. A second look at the data can often yield hidden treasures, such as fracture characterisation, permeability, wellbore stability, hole size, cement evaluation, production optimisation, brittleness maps, and much more.
In this presentation, we discuss some of the many gems that can be mined from acoustic waveform data. Included is a brief review of the "flavours" of acoustic tools appropriate for each application as well as tips for optimising data
Primary Technical Discipline: RDD
Jennifer Market is currently the Global Acoustics Advisor for Weatherford. Her role involves acoustic data processing and interpretation, along with development of software and new application. She also provides industry training seminars to widen the understanding of acoustic data acquisition and applications. She has 15+years’ experience in borehole acoustics, working in a service company to develop acoustics tools and applications. She frequently publishes articles for both SPWLA and SPE and was an SPWLA lecturer in 2008-2009 and 2011-2012.
We all agree it is necessary to have an adequate safety culture to minimize the possibility of major accidents. This presentation explains what is meant by a “safety culture”, and provides guidance as to what is required to develop an adequate culture of safety and assure it actually exists in practice. A change in safety requires a change in attitudes and actions on the part of both management and worker. Both the Operator and the regulator have a role to play in making this happen.
Primary Technical Discipline: HSSESR
Ken Arnold has almost fifty years of industry experience with 16 years at Shell Oil Company. He founded Paragon Engineering Services in 1980 which was voted one of the best places in Houston to work by the Houston Business Journal. In 2005 Paragon was purchased by AMEC. In September 2007, Ken retired from AMEC and formed K Arnold Consulting, Inc. (KACI). In 2010 he joined WorleyParsons as a part-time Senior Technical Advisor while maintaining KACI for independent consulting work.
Ken is co-author of two textbooks and author of over 50 technical articles on safety management, project management and facilities design. He has twice been chosen as an SPE distinguished lecturer. He has twice served on the Board of SPE, is currently Treasurer-Elect of The Academy of Medicine, Engineering and Science of Texas and a former member of the Marine Board of the National Research Council. He was Chair of the National Research Council Committee which prepared a report for the Department of the Interior on "Evaluating the Effectiveness of Safety and Environmental Management Systems for Offshore Operations".
Ken has taught facilities engineering at the University of Houston as well as for several oil companies. He is a registered professional engineer and serves on the advisory board of the engineering schools of Tulane University and Cornell University and the Petroleum Engineering Advisory Board of University of Houston.
Mr. Arnold was an SPE Distinguished Lecturer in 1994-95 & 2002-03.
Information about fluid properties is a required input for every stage in the oil and gas industry from the reservoir to the refinery. It is therefore of utmost importance for reservoir, facility and corrosion engineers to understand the volumetric behaviour and the transport properties of the produced fluid. These fluid properties can be obtained from PVT reports generated either in-house or in external labs. In both cases, engineers should be able to perform a consistency check on the data before including it in their respective tasks.
This presentation provides an overview of tools for verifying the consistency of PVT data. Among them are mass balance, cross plots and the Y-function for the constant composition experiment (CCE) and for the differential liberation experiment (DLE) for oils. As well, basic quantities, like thermal expansion or oil compressibility always have to lie within a certain order of magnitude. The formation volume factor Bo, the compressibility and the viscosity of oil depend more on the amount and only to a lesser degree on the composition of solution gas. Based on the idea of ideal solutions one can find estimates for Bo,Co,µo. Correlations for oils applicable to different oil provinces complete the checks for oil. For gas-condensates the CCE gives valuable insights into the quality of the experiment. The constant volume depletion (CVD) for gas-condensates is more difficult to check, but calculating the K-values can serve as a quality control. In both cases, black oil and compositional, it is customary to model the experiments with equations of state (EOS).
Primary Technical Discipline: RDD
Klaus Potsch is a retired Senior Expert from OMV and also serves as a consultant for Fluid Studies. He holds a BS and MS in Physics, and a PhD in Mechanical Engineering from the Technical University of Vienna, where he also worked as an Assistant Professor. For the last 4 years he has been a guest lecturer for "Reservoir Fluids and their Modeling" at the Mining University of Leoben, Austria. In his professional career he headed the team of Mathematics, Reservoir Engineering and finally High Pressure Technology in the Laboratory of Exploration and Production of OMV. Within SPE he has held several positions in the Vienna Basin Section board and from 2003-2008 served on the International Board of SPE as the Regional Director for South, Central and Eastern Europe. Klaus was also on the SPE Distinguished Lecturer Committee from 2003-06.
The Science and Engineering of Internal Corrosion Control in the Upstream Petroleum Industry … mainly about managing water …
Unsuccessful control of internal corrosion has historically caused catastrophic incidents in the the upstream petroleum industry. Corrosion control requires a synergy between a sound basis of design and an appropriate operability philosophy. Equipment used in upstream operations may include but not limited to casing, production tubings, risers, flowlines, pipelines and facilities. Corrosion control related decisions made at design level and guidelines set for operations will always be driven by water management. Ranging from lowering water content in oil export lines to tightening water specification in pipelined gas, guidelines to control corrosion are strongly based on water quality and movement within the equipment and the process. While corrosion prediction and mitigation involve thorough understanding and application of scientific concepts of water chemistry, flow dynamics, and transport phenomena; corrosion monitoring/inspection requires sound engineering practices in order to track water, monitor changes and meet internal and external requirements. The success of corrosion control programs is also strongly affected by the level of collaboration and integration within the asset integrity and operation teams.
Primary Technical Discipline: PFC
Mohsen Achour is currently leading the corrosion, inspection and materials group within Global Production Excellence Division of ConocoPhillips USA. He holds a PhD in Chemical Engineering and Materials from Oklahoma State University and Adjunct Professor honorary title from Ohio University Institute of Corrosion and Multiphase Technology Center. He had held an Associate Professor of Chemical Engineering position at the University of Carthage in Tunisia for 11 years before joining ConocoPhillips in 2006. He has published more than 60 technical papers and patents in the areas of transport phenomena and corrosion and supervised more than 20 Master and PhD students. He is a member of SPE and NACE International and has been extensively active chairing multiple technical committees, sessions and symposiums in regional and international events for both organizations. He is recipient of multiple internal ConocoPhillips technology innovation, collaboration, and technical achievement awards over the past few years.
Managed Pressure Drilling (MPD) has been offered over a decade now. The common thinking is that MPD has the potential to be a widely used enabling technology in the future, but has been met with relatively limited acceptance by oil companies. One of the key factors to adopting technology is better communication of its benefits using more detailed case studies. The other major factor is that MPD is a complex, multidisciplinary activity that requires specific skills and resources to ensure project engineering/management and strict HSE management. Confusion about MPD’s application may also have contributed to its slow acceptance rate. To overcome these challenges requires a paradigm shift in thinking.
Saudi Aramco’s drilling program could benefit from MPD. A 2012 NPT analysis revealed that MPD can reduce lost time by 23.5%. Saudi Aramco has recognized MPD as one of the key initiatives that will enable it to optimize its drilling operations. The targeted areas in Saudi Aramco are tight gas formations, extended reach wells, high pressure and loss circulation prone workover wells as well as some exploratory wells. This presentation will highlight some of the case studies, as well as lessons learned on the MPD implementations. Sharing the true MPD benefit will enhance the adoption of this enabling technology in a wider scale including frontier applications, such as HPHT, deepwater, Methane hydrates and unconventionals.
Primary Technical Discipline: DC
Muhammad Muqeem is a Drilling Engineering Specialist with over 20 years of international expertise in the area of underbalanced/managed pressure drilling, wellbore hydraulics, and multiphase fluid flow in porous media. He has extensive experience in horizontal, multilateral wells including coil-tubing and sour drilling. Muhammad has authored and co-authored several SPE papers on multiphase flow, casing drilling, stuck pipe and underbalance drilling. Contributing author of Gulf Publishing Company's "Underbalanced Drilling: Limits and Extremes" book. He received a Ph.D. in petroleum engineering from the University of Alberta. He was the project lead and instrumental in the first ever implementation of UBD in Saudi Arabia. Muhammad is currently employed by Saudi Aramco in the Drilling Technical Department and is a member of SPE and APEGA.
Wellbore Position, Quality Control, Gross Errors and Error Models
Good wellbore positioning; including techniques for avoiding collisions or finding and intersecting other wells is critical to control catastrophic blow out accidents, rescue stranded miners, drill close proximity wells with minimal environmental impact, or drill wells with complicated trajectories that access new reservoirs.
The trajectory of an oil well is at best an estimation of where the well is, based on available measurements. Uncertainties on the position of the wellbore increases as points on the wellbore trajectory are further away from the wellhead. An error model represents the survey tool behavior, modeling errors and uncertainties of the tools and accounting for measurement procedure. The result is a statistical representation of the uncertainty, with a 3D ellipsoid centered at each survey point of the wellbore trajectory.
Quality control of the data to assure the correct measurements, readings taken within the range of tool calibration, magnetic measurements free of magnetic interference, etc. is crucial to avoid gross errors. Internal quality control in a survey is not by itself sufficient to assure a survey free of gross errors. Performing two independent surveys is the best way to detect gross errors and to confirm that a survey can be represented by its error model. The use of data without the adequate QC is risky and does not provide assurance of the position of the well or its uncertainty. Several examples will be used to illustrate the benefits of directional data quality control.
Primary Technical Discipline: DC, RDD
Nestor Eduardo Ruiz received his Electronic Engineer degree at the University of Buenos Aires Argentina. He started his career in 1983 as a field services engineer and then moved into development and producing directional software, for planning and controlling wellbore trajectories, of directional wells. He was in charge of the directional drilling magnetic survey tools and software. He planned the trajectories of the first horizontal wells drilled in Argentina which also included blow out well experience. As LAS manager for Gyrodata, In 2010 he was involved in the planning and supervision of the gyro directional drilling surveys, in the C miner rescue plans in Chile.
Nestor also was SPE chairperson of the Patagonia section and gave presentations of directional surveys in universities of Argentina, Brazil and Peru in the last years. He also participate in several ISCWSA meetings. In addition to English, he speaks Spanish and Portuguese.
Nearly 40% of today’s oil production comes from mature fields and this proportion is increasing. A significant portion of operating costs in brown fields is related to lifting costs and maintenance of artificial lift equipment. Often additional costs for workovers arise due to sub-optimal corrosion control or when sand production becomes an issue (unconsolidated reservoirs) or as the result of a long water flood history. Any combination of these problems can lead to premature abandonment of the field despite the fact that significant oil and gas reserves remain in the reservoir.
In order to combat this loss of reserves and valuable energy resource a number of measures have to be taken. There are two keys to success: 1. the analysis of available technologies along the production chain, the identification of advanced materials and the development of stringent processes all directed to extend the lifetime of the equipment. 2. A dedicated team from all disciplines working with the asset to create tailor-made solutions for the particular applications in the field.
The presentation will provide a field case showing this process and will give a detailed insight of the basket of technical solutions and the commercial impact.
Primary Technical Discipline: PO
Siegfried Müssig is currently working as Technology and Quality Manager at RAG. He holds a Diploma and a PhD in Physics of the University Karlsruhe, Germany. Between 1982 and 2002 held several technical and management positions at the German affiliate of Shell, BEB Erdöl and Erdgas GmbH. Between 2002 and 2006 he worked for Shell International in Rijswijk, The Netherlands, where he was a founding member of the Smart Fields Initiative and worked as Regional Coordinator for the Middle East and Africa. Between 2006 and 2008 he was Development Manager "Under Ground Gas Storages (UGS)" at RAG focusing on the storage project "7Fields" where seven independent gas fields were integrated into one UGS. Between 2008 and 2011 he was Manager Well Technology for Maersk Oil, Copenhagen, Denmark. Throughout his entire career he was dedicated to innovative technologies when conventional solutions failed. In this capacity he was appointed as board member of the Ceradyne Inc. Group and PLECon Engineering GmbH.
S. Müssig has published 35 technical papers and 6 patents, is a guest lecturer at the University of Leoben, Austria and an active SPE member, he served e.g. as Chairman of the German SPE section in 1994/5)
A 250 year history of scientific development preceded the first synthetic diamond. Finally, in the 1950’s, when understanding and equipment aligned, the breakthrough came, man finally made diamond. A period of increasing understanding of the manufacturing process followed, leading to a new product every year for machining of non-ferrous materials. Two decades further on, in 1973, the polycrystalline diamond compact was invented but it took another seven years of development before it established itself as the new drilling product for oil and gas wells. Early this century, following a further twenty years of innovation, peaking with the invention of a thermally stable PDC, the PDC bit market finally exceeded that of the roller cone bit, the leading drilling product for nearly a century. A decade has passed since the last great innovation but exponents of the synthetic diamond art have demonstrated, throughout its history, a thirst to drive the technology forward. How will they combine the latest knowledge and newest equipment for improved drilling products?
Primary Technical Discipline: DC
Terry Matthias holds a BSc in Mechanical Engineering, is a Chartered Engineer and a Fellow of the Institute of Mechanical Engineering in the United Kingdom. He joined Drilling & Service, a drill bit company, in 1980 at the very beginning of the successful commercialisation of polycrystalline diamond compacts bits. For the last 33 years he has worked on and managed PDC bit and cutter design/development. He established a PDC manufacturing facility in the UK and led the team that invented an industry changing, and award winning, thermally stable PDC. He is named inventor on 23 US patents.
Shale resource development technology is being improved and optimized for the past 5 to 7 years as the industry saw a sharp rise in activity throughout North America and other emerging countries. Despite such improvements and optimization, the performance of these wells illustrates that not all wells are producing commercially and, for that matter, in wells that are producing commercially, not all hydraulic fracture stages are contributing. In this lecture, well-defined criterion will be identified and used to isolate the sweet spot location within a field for optimal well placement. The lecture will also cover vital formation/zone characteristics that can identify the placement for hydraulic fracture stages and thus move away from the arbitrary geometric placement. Examples from three basins illustrate the practical application of the methodology
Primary Technical Discipline: RDD
Usman Ahmed is vice president of unconventional resources global market segment and chief reservoir engineer at Baker Hughes. Ahmed has more than 30 years of practical petroleum engineering experience and holds a BS and MS in petroleum engineering from Texas A&M University. He has more than 70 publications, textbooks, and patents.
With the decrease in the possibility of discovering new giant oil fields, mature fields become critically important for meeting future oil demands. Special attention is required for identifying the proper diagnostic techniques to determine the reason for and the location of the unrecovered oil and prudential reservoir management techniques for economically viable redevelopment applications. In this lecture, after discussing the methods to estimate the amount and location of the residual oil, attention will be given to the most widely applied enhanced oil recovery methods to develop mature fields—primarily chemical and immiscible/miscible gas injection. After reviewing mid- and late-stage development options using these methods, proper reservoir management strategies for different size companies will be discussed.
Primary Technical Discipline: RDD
Tayfun Babadagli is a professor of petroleum engineering at the University of Alberta where he is a senior chair holder of Unconventional Oil Recovery in the Natural Sciences and Engineering Research Council of Canada. He earned BS and MS degrees from Istanbul Technical University and MS and PhD degrees from the University of Southern California. Babadagli is the executive editor of SPE Reservoir Evaluation & Engineering.
Characterizing Shale Plays—The Importance of Recognizing What You Don’t Know
Understanding the uncertainty in individual well performance is particularly critical during the exploration drilling program where there are relatively few wells on which to base decisions. Key questions during the early phases include "How many wells do I need to drill before I have confidence in the results?" and "Does the well performance I’ve seen to date provide the encouragement needed to keep drilling?" Understanding the uncertainty in well performance, and planning for it will lead to more efficient exploration activity and better informed decision-making.
Primary Technical Discipline: RDD
Brad Berg is the reservoir engineering manager for US onshore exploration at Anadarko Petroleum. He has been instrumental in developing the methodologies and tools that his company uses to evaluate unconventional resource plays.
Perforating for Inflow Performance in Natural Completions
Delivering well performance in tighter and more marginal reservoirs requires a greater degree of focus on the interface between the wellbore and the reservoir. Conventional perforated wells still represent a majority of completions, and optimizing the perforation by applying both relevant perforating technology and modeling can provide significant gains in both net present value, ultimate recovery, and, in some cases, project cost. There have been significant changes in the way we measure and model charge and gun performance in recent years. This combined with several emerging technologies have made the process of perforating optimization both more valid and more useful. Technology and modeling tools now make it possible to identify the optimum perforating scheme. Take advantage of the new modeling tools, methods of measuring perforator performance, and the latest perforating technology to make perforations deliver.
Primary Technical Discipline: DC
Mark Brinsden is Shell’s global perforating lead with 34 years of experience in well technology. Brinsden is the chair of the API perforating committee and cofounder of the International Perforating Forum. He is also involved in the development of several new gun systems.
Geomechanics and Fractured Reservoirs: Comforting, Confusing, or Scary?
Fractured reservoirs often exhibit interaction between production and effective permeability. Simple rules used to explain this relationship are based on assumptions that are physically impossible. Moving beyond this limitation requires a change of mind-set. By using simulation models and realistic conditions, where fractured rock masses and their contained fluids are suitably represented, the way in which coupled systems interact can be understood, leading to realistic upscaled responses. Many real-world fractured reservoirs may have fracture distributions and flow conditions that never raise any major surprises. However, in other parts of those reservoirs, confusing responses may appear because of the nonlinear geomechanics/fluid interactions, and some examples may demonstate seemingly unreasonable behaviors.
Primary Technical Discipline: RDD
Gary Couples is a professor of geomechanics at Heriot-Watt University's Institute of Petroleum Engineering, where he links geomechanical processes to their consequences. His research and teaching activities range from the pore scale to the reservoir scale and larger with an emphasis on predicting effective flow and other emergent phenomena.
Selective water-reduction systems with consistent, sustained performance have been pursued by the oil and gas industry for many years. A few systems are currently reporting success and alternate application in other areas, such as additives to fracturing fluids, diverters for acidizing treatments, and leak-off control agents. This presentation discusses the mechanisms of selective water-reduction systems, case histories for both water reduction and alternate applications, and how this class of compounds and their applications could potentially be improved for increased success in the future.
Primary Technical Discipline: PO
Larry Eoff is a chemist at Halliburton in Houston. He holds a BS in chemistry from the University of Central Arkansas and a PhD in organic chemistry from the University of Arkansas.
Stimulation processes in unconventional resources impose extreme loads on both producing formations and the wells used to access them. This lecture will examine the range of issues emerging from these processes and how the responses can be measured to help address the challenges and improve the performance of projects. This lecture will also focus on deformation mechanisms of unconventional resource development and demonstrate root causes of several deformation mechanisms. The topic extends beyond the well and how the well can be an instrument to gain insight into formation response to these new processes.
Primary Technical Discipline: DC
Trent Kaiser is a principal consultant at Noetic Engineering in Canada. A primary focus of his work has been on strain-based design for extreme oilfield applications. He is a lead developer and presenter of numerous training courses for unconventional resources. Kaiser earned BS, MS, and PhD degrees in mechanical engineering and has numerous publications, including more than 30 patents.
Unconventional reservoirs are just that—unconventional. Extrapolation of techniques that have been used in conventional reservoirs to unconventional reservoirs is dangerous and can prevent further development by providing poor results. In order to avoid such misapplications, unconventional reservoirs call for unconventional thought processes. There is no place this is more evident than in hydraulic fracturing in which a different mind-set has to be developed, not just for unconventional reservoirs in general, but specifically for each type of individual system. This presentation reviews the changing perspectives and design considerations. The main “takeaway” is that unconventional reservoirs have requirements very different and distinct from conventional reservoirs and designs can be improved by considering these unique requirements.
Primary Technical Discipline: PO
Jennifer Miskimins is a senior consulting engineer at Barree & Associates where she specializes in stimulation treatment design and analysis and teaches short courses. Before joining Barree, she was an associate professor at the Colorado School of Mines. Miskimins holds a BS, MS, and PhD in petroleum engineering.
This lecture discusses acid fracturing stimulation in deep hard carbonates and etching patterns. Laboratory tests were performed to verify whether an acid-induced fracture can withstand the high effective normal stresses acting in such reservoirs. Many published results from small, wet sawed, and leveled carbonate rock samples support the claim that different acid etching patterns determine different conductivity behavior. However, hydraulic fractures are tensile fractures and they are naturally rough. Experimental results show that after acid reaction, roughness of tensile fractures can have more, equal, or less roughness than before acid reaction.
Primary Technical Discipline: PO
Luis F. Neumann is the technical adviser for stimulation and sand control at Petrobras. He has more than 25 years of experience pumping wellbore fluids at fracturing pressures using hydraulic, acid fracturing, and frac-pack techniques in vertical, deviated, and horizontal subsea wells.
A Step Change in Traditional Risk Assessment Techniques for Process Safety and Asset Integrity Management
The oil and gas industry has recognized process safety and asset integrity as key drivers for maximizing asset performance and preventing major accident hazards, which results in the preservation of human lives, the environment, and assets. This lecture discusses the possibility of overcoming limitations of standard risk assessment techniques with a new tool called BAseline Risk Assessment Tool (BART). The tool represents a step change in traditional risk assessment because it combines two mature methodologies, quality risk assessment and bow-tie analysis, to assess process safety hazards as well as analyze the existing safety barriers and their contribution to risk prevention and mitigation. Basic process safety concepts will be presented to the audience, and the rationale and features of BART will be discussed and compared with existing techniques.
Primary Technical Discipline: HSSESR
Annamaria Petrone works as a senior safety engineer for Eni E&P. She has 10 years of experience in the oil and gas industry. Her professional skills include risk assessment, process safety, and maintenance. Petrone holds an MS in civil engineering and a post-university master in reliability availability and maintenance.
For the unprepared, liquid slugs in multiphase pipelines can have disastrous consequences, including increased corrosion, production impairment, compressor damage, flooding of separators, and damage to process equipment. The key to avoiding problems with slugging in pipelines is to determine the type and magnitude of the slug now and into the future. This lecture will outline procedures for handling and modeling each of the four types of slug using both steady state and transient modeling tools. Once the kind and size of slug is determined, then the appropriate steps can be taken to avoid problems.
Primary Technical Discipline: PO
Mona Trick is a licensed profession engineer and an adviser for the SPT Group, a Schlumberger company. For the past 30 years, she has advised clients on handling slug flow and modeling and matching multiphase wellbore and pipeline pressure losses. She earned a BS in mechanical engineering from the University of Calgary.
Production of shale gas requires large volumes of water for preparing drilling and fracturing fluids. Following the completion of the fracturing job, some of the injected water returns to the surface as flowback and produced water and must be managed appropriately. This lecture discusses water availability for several major US shale plays and describes the types of water management technologies and practices used in North America for flowback and produced water.
Primary Technical Discipline: HSSESR
John Veil is the president of Veil Environmental. He has written many reports and given numerous presentations on produced water, flowback water, hydraulic fracturing, and shale gas. Veil has 33 years of experience in water management.
Most natural gas reserves are considered as stranded because of a lack of adequate and diversified transportation. Gas can be transported with on-land pipelines, but it becomes very expensive with underwater pipelines. The main alternative is liquefied natural gas. Other options include compressed natural gas and gas-to-liquids. For compressed natural gas, the development of composite material containers has proven to be a game changer, and gas-to-liquids has changed over the years from diesel and jet fuel to alcohols. This lecture presents new information from recent experiences and attempts to provide a methodology of technical and economic optimization for the transportation of natural gas. Worldwide demand for natural gas is expected to force the issue because of massive new needs headed by China.
Primary Technical Discipline: PFC
Xiuli Wang is vice president and chief technology officer of XGas and an adjunct professor at the University of Houston. She is the lead author of the book, Advanced Natural Gas Engineering, and a contributing author to Modern Fracturing—Enhancing Natural Gas Production. Wang holds a PhD in chemical engineering.
The Arctic continental shelf is believed to be the area with the highest unexplored potential for oil and gas. Despite a common view that the Arctic has plentiful hydrocarbon resources, there are ongoing debates regarding the potential of this region as a future energy supply base. Driving forces for such discussions are geopolitics, environmental concern, assessment and delineation of Arctic resources, technology available for their successful development, and the market demand for energy supply. This lecture examines the future role of the Arctic region in addressing the evolving energy demands.
Primary Technical Discipline: PO
Anatoly Zolotukhin is a professor at the Gubkin Russian State University of Oil and Gas. He serves as deputy chancellor on international affairs and is a director of the Institute for Arctic Oil and Gas Technologies. Zolotukhin earned an MS in applied mathematics and an MS and a PhD in petroleum engineering.
This presentation will describe the well-management process used by Petrobras to design and drill exploratory wells. The case of an offshore well drilled in a remote area of the Black Sea will be examined. Ranked as a well of the highest complexity level, the drilling of this ultra deepwater wildcat well has faced a number of expected hazards, such as the presence of shallow gas zones, long abnormally pressurized intervals, and low fracture pressure gradient sections.
Primary Technical Discipline: DC
Luiz Alberto Santos Rocha has worked for Petrobras for more than 32 years. He is currently the Senior Advisor of the International Drilling Group. He holds degrees in mechanical engineering and MBA both from the Pontíficia Universidade Católica do Rio de Janeiro. He also holds a Ph.D. degree in Petroleum Engineering from Louisiana State University (LSU).
While remote parts of the world are awash with hundreds of Tcf of natural gas, the industrialized West and emerging economies of the East cannot get enough of the clean-burning, environmentally friendly fuel. This presentation will provide an overview of natural gas liquefaction facilities, from inlet gas receiving to liquefied natural gas (LNG) storage and loading. However, the focus is on the liquefaction process and equipment.
Primary Technical Discipline: PFC
Mike Choi is a process engineering fellow in ConocoPhillips’ Global Production Department in Houston. His specialties are production facilities, sour gas treating, and LNG.
Methods and Workflows to Process Dynamic Data in Intelligent Fields
In the past years well tests have been complemented and partly replaced by a variety of tools that provide dynamic rate, pressure, and temperature data at various scales. Well Test Interpretation has also progressed into a variety of methods to analyze pressure and rate data, using increasingly sophisticated models. With Intelligent Fields, the demand is to move towards a workflow that will also address permanent data proliferation and information overload. This lecture provides a holistic description of past, present and future solutions around these issues.
Primary Technical Discipline: RDD
Olivier Houzé holds an engineering degree from Ecole Polytechnique and an MS degree in petroleum engineering from Stanford University. He is the incoming SPE Technical Director for Reservoir Description & Dynamics for 2012–2015.
Shale Resources Assessment – A Full Life Cycle Integrated Approach
Key issues and uncertainties in shale resource development are resolved as plays move from resource assessment to full scale development utilizing a full life-cycle integrated approach essential for value creation and ensuring growth in production and reserves. The design, planning, and implementation of systematic and scalable Field Demonstrations are essential elements required to address strategic, development, and operational issues. Mechanistic studies are used to understand the key production drivers. This presentation demonstrates the application of new processes and advances which are key to appraisal and development of global shale resources.
Primary Technical Discipline: RDD
Pankaj Kumar (PK) Pande is director of reservoir technology / reservoir characterization for Anadarko Petroleum Corporation. His responsibilities include managing an integrated team of subsurface professionals in application of subsurface technologies and best practices for deepwater and unconventional resources worldwide.
Advanced Drilling Solutions
The presentation will discuss the various types of drilling dynamics related issues which contribute to poor performance. A variety of methods to identify and mediate the primary cause of performance issues will also be addressed from proven methods.
Alan Clarke is a 15 year veteran in the oil industry with extensive background in a variety of drilling products, services, and training systems. He holds a BSc from Memorial University of Newfoundland’s earth Science department, and is currently the Director of Advanced Drilling Solutions for National Oilwell Varco.
Asphaltenes and associated production challenges still receive a lot of attention in the E&P operations. The key in tackling those challenges is to understand the diverse world of asphaltenes – their origin, changes to their chemical structure during generation and migration of hydrocarbons, and in consequence their behavior during production.
Dr. Artur Stankiewicz is Schlumberger’s Reservoir Fluids and Flow Assurance Domain Head, and Advisor Reservoir Fluids & Geochemistry.
Fiber-optic technology, although only introduced for use in E&P well and reservoir monitoring in the last ten years, has blossomed into a highly reliable set of tools which frequently offer monitoring capability not obtainable with traditional sensors which are either permanently installed or run as logging tools or via other intervention methods. This Distinguished Lecture will provide an overview of optical sensing techniques and sensors such as distributed temperature sensing (DTS), optical pressure gauges, distributed strain measurement for integrity monitoring and distributed acoustic sensing, describe various deployment methods and discuss examples which illustrate the role of fiber-optic monitoring in well and reservoir management.
Dr. Dennis Dria, Petroleum Technology Advisor and President of Myden Energy Consulting, PLLC, has more than 20 years of experience with Shell, most recently working as a Staff Research Engineer in the areas of fiber-optic technology development, fiber-optic data management and integration and technology implementation for well and reservoir monitoring, and as Shell's Global Subject Matter Expert for production logging and permanent sensing.
This lecture presents a discussion of the key characteristics of shale reservoirs and their impact on the performances of fractured horizontal wells. Examples are presented to highlight common practices and discuss performance interpretation problems.
Erdal Ozkan is a professor of Petroleum Engineering and co-director of Marathon Center of Excellence for Reservoir Studies at Colorado School of Mines.
By integrating surface and downhole data with dynamic drilling models and the rig's drilling machines we can automate and optimize the drilling process occurring below the rotary table. This presentation outlines the current industry efforts to implement automation tools for conventional rigs as well as high-end deepwater units and examines the changing roles within the drilling team.
Fred Florence is a Product Champion at National Oilwell Varco (NOV) and is the current chairman of SPE’s Drilling Systems Automation Technical Section (DSATS).
Managed Pressure Drilling-MPD, from the core concept point of view, is a collection of drilling optimization techniques, when correctly designed, planned and applied, will improve the overall drilling performance and mitigate risks. MPD is a step-change technique that increases recoverable assets, reduces NPT, enhances safety and reduces the total drilling cost.
Hani Qutob is the Reservoir Engineering Manager for Weatherford “Well Engineering Centre of Excellence” – Middle East and North Africa. Hani has 30 years of diversified international experience in the oil & Gas industry and was the SPE Distinguished Lecturer for the 2007-2008 Season.
This presentation discusses the state of the art in openhole sand control completions, reviewing the evolution of developments in the last decade, highlighting recent advancements and the gaps for future work towards healthier sand control completions in openhole environments.
Mehmet Parlar is a Technical Advisor for Schlumberger Sand Management Services, based in Houston, Texas
This presentation disseminates the integration of state-of-the-art engineering approaches, innovative technical initiatives and new technologies in optimum hydrocarbon exploitation plan from the oil rim reservoirs. The applied fundamentals, critical elements and proven practices for effective reservoir management and hydrocarbon recovery enhancement efforts with lower cost are elaborated through various successful real case studies.
With over 14 years of industrial and academic work experiences, Dr Rahim Masoudi is currently a Principal Reservoir Engineer for Petroleum Resource Development in PETRONAS, and also Adjunct Professor in University Technology PETRONAS.
The lecture will address the approaches to preventing/mitigating these mechanisms which involve excellent well planning, real-time monitoring as well as sound drilling practices
Dr. Samuel O. Osisanya is an Associate Professor of Petroleum Engineering at the Mewbourne School of Petroleum and Geological Engineering at the University of Oklahoma in Norman, Oklahoma, USA for 19 years, where he teaches all aspects of well construction technology and had practical field experience with Gulf (now Chevron), Shell-BP and Mobil (now ExxxonMobil).
This presentation exposes a common misunderstanding about the true nature of uncertainty – the fact that it is in our heads, not in the systems we deal with. This has profound implications for uncertainty assessment.
Steve Begg is a Professor at the Australian School of Petroleum where his teaching and research focus is on asset and portfolio investment decision-making under uncertainty. He holds a PhD in Geophysics and a BSc in geological geophysics from Reading University.
EOR has not been present in the offshore; while applications present logistical as well as technical challenges, the offshore represents a large EOR opportunity. To achieve and exceed the expectations of EOR's contribution to supply, innovative political and commercial approaches are needed; for example, agreements regarding CO2 capture and transportation, NOCs and IOCs sharing the risk as well as the reward in EOR applications.
Paul Bondor retired from Shell after 35 years of technical and supervisory service. He holds BS, MS, and PhD degrees from Case Institute of Technology.
This presentation covers carbon management, sustainable development, global requirements, trends & initiatives. The carbon strategy devolves around company’s own perspective on the global issues of climate change mitigation, adaptation & offsetting.
A.B. Chakraborty, Chevening fellow, University of Cambridge 2009, is currently the Chief – Carbon Management Group in ONGC & deals with CDM projects development, climate change and sustainable development strategy. He has BE (Mech.), MTech, MBA, MSc (environmental science) and PG diplomas in environmental management/economics.
Advanced Geosteering Methods for Optimal Recovery of Hydrocarbon Reserves
This presentation addresses the new technologies that continue to emerge to help geologists, drillers, and reservoir engineers make well-informed geosteering decisions.
Roland Chemali is Chief Petrophysicist with Halliburton-Sperry Drilling Services. He holds engineering degrees from the Ecole Polytechnique of Paris and the French Petroleum Institute IFP.
Putting the Focus on Data
This presentation focuses on data as a critical business asset that drives decisions on where to invest, when to divest and how to operate more efficiently. Management of data in silos is discussed.
Jim Crompton holds the position of Manager of Upstream Architecture in the Chevron Global Upstream IT organization. He earned a BS in geophysical eng., MS in geophysics from the Colorado School of Mines and an MBA from Our Lady of the Lake University.
This presentation illustrates that well barrier problems are not limited to being internal and deep in the well and require expensive (i.e., rig) methods to repair. Inexpensive repair approaches "outside the box" of traditional methods can be done safely, reduce risk and provide economic value for the company.
Jerald C. Dethlefs is a Well Integrity and Diagnostics Engineer with ConocoPhillips in the Global Completions and Production Engineering Group in Houston, Texas. He has a BSc in general engineering, an Ms in civil engineering and an MBA.
This presentation includes several examples to illustrate the power of real time monitoring and interpretation and argues that real-time monitoring and control is required to ensure that the critical formation testing objectives are met on any exploration, appraisal or otherwise high profile project.
Hani Elshahawi leads FEAST, Shell’s Fluid Evaluation and Sampling Technologies center of excellence, which is responsible for the planning, execution and analysis of global high profile formation testing and fluid sampling operations. He has a BSc in mechanical engineering and an MSc in petroleum engineering from the University of Texas at Austin.
Research in nanotechnology is giving new insight into why the asphaltenes interact with each other, enabling new approaches to remove unwanted contaminants, to develop new catalysts, and possibly to enable synthesis of new materials derived from heavy oil. A wide range of new upgrading technologies have been proposed, but insight into the behavior of heavy oil at the nanometer scale allows us to analyze which of these approaches can be cheaper than current commercial technology, and which ones are unlikely to succeed.
Murray Gray has over 20 years of research experience in upgrading of heavy oil and oil sands bitumen. He is currently Director of the Centre for Oil Sands Innovation at the University of Alberta. He obtained his PhD in chemical engineering from the California Institute of Technology in 1984. He also holds an MEng degree with a specialization in petroleum engineering from the University of Calgary (1980) and a BSc in chemical engineering (with honours) from the University of Toronto (1978).
This presentation highlights the areas that need to be tackled in order to make intelligent well technologies relevant to mature fields, and to make these technologies more effective in general. Focus is on the measures that can be realistically achieved in the course of the next 10 years.
Younes Jalali is a Reservoir Engineering Advisor with Schlumberger. He holds BS and MS degrees from the University of Tulsa and a PhD from the University of Southern California, all in petroleum engineering.
The first part of the presentation describes the steam-based thermal recovery processes, in terms of recovery efficiency and environmental impact. The second part of the presentation describes a new heavy oil recovery technology that has been developed not only to maximize the performance but also to minimize the environmental impact.
David Law is currently the Schlumberger Heavy Oil Technical Director in North America with offices located at both the DBR Technology Centre in Edmonton and the Heavy Oil Regional Technology Centre in Calgary, Alberta, Canada. He holds a BSc degree from the National Taiwan University in Taipei, Taiwan, and MSc and PhD degrees from the University of Alberta in Edmonton, Alberta, Canada, all in chemical engineering.
This presentation identifies the various “stages” of optimizing a gas lifted production project and reviews recent advances in equipment, software and concepts which are changing the way gas lift is applied and engineered. The importance of suitable surveillance, data acquisition and management systems will be stressed.
Rick Lemanczyk has served as the Principal Petroleum Engineer in Senergy’s Asia Pacific operations, located in Kuala Lumpur, since 2006. He holds a PhD in chemistry from Oxford.
Diagnostic injection tests can provide information on reservoir characteristics; and reserve recoveries can be enhanced through practices such as improved well spacing and reorientation of fracturing treatments. This presentation reviews these changing perspectives and design considerations.
Jennifer L. Miskimins is an Associate Professor in the Petroleum Engineering Department at the Colorado School of Mines (CSM) in Golden, Colorado, USA. She holds BS, MS and PhD degrees in petroleum engineering.
Let’s Model It! 3D Geoscience Modeling: Implications for Reserves Estimation and Field Development Planning
This presentation reviews the geoscience modeling as an initializing technology for reservoir simulation and from the perspective of key deliverables such as recoverable volumes. By correctly identifying rock that contributes to flow and honoring scale issues, the link between 3D geoscience and engineering models becomes more seamless, a benefit that is manifested through more readily attainable history matches.
Douglas Peacock is a Senior Geoscientist with Gaffney, Cline & Associates. He holds a BSc in geological sciences from Leeds University, UK, and an MSc in petroleum geology from Imperial College, London.
This presentation reviews a series of case studies to demonstrate how the challenge of effectively managing international SE programs can impact development projects and how applying the Next Generation Stakeholder Engagement can help meet this challenge. It provides recommendations for how to improve capacity building activities and optimize opportunities for local involvement, and ultimately success, in stakeholder consultation.
Dean Slocum, SPE, is the Principal and founder of Acorn International and a former director of the energy and environment practices of Arthur D. Little and Battelle Memorial Institute. He has a Bachelors degree in sociology and a Masters degree in public administration/health.
The Determination Of Minimum Tested Volume And Future Well Production From The Deconvolution Of Well Test Pressure Transients
The use of the derivative is now a standard technique in pressure transient analysis. Deconvolution is a more recent method that, thanks to improvements in the algorithms, is becoming accepted practice. The combination of these two powerful methods has significant implications on how pressure transient data can be analyzed. Before attempting to find a plethora of models that fit the observed data, there is much information that can be obtained from the data directly.
Tim Whittle is a Group Technical Authority for pressure transient testing at BG-Group in Reading, UK. He has a Masters degree in engineering science from Cambridge University, England, and has worked in the oil industry for more than 25 years.
This presentation will review current procedures and provides important new developments from shallow to ultradeepwater scenarios and regarding infill drilling projects for mature fields. A comparison of technologies will be provided based upon impact upon well productivity or injectivity.
Agostinho Calderon is a senior adviser in the completion, sand control, and stimulation, engineering team for Petrobras E&P Services in Brazil. He earned a B.S. degree in civil engineering from State University of Rio de Janeiro and a Post Graduation Course in petroleum engineering from Petrobras University.
This presentation will give an illustration of new improvements with two examples, a successful polymer flood project implemented in a heavy oil reservoir, and a successful water shutoff/sand consolidation treatment by microgels in an underground gas storage well.
Alain Zaitoun is vice president of Poweltec. He earned a PhD degree in chemical engineering from University of Nancy, France.
This presentation focuses on the application of latest design, chemicals, software, and equipment technology for drilling and completing in challenging scenarios.
Andre Leibsohn Martins is a senior consultant in the well technology sector at the Petrobras R&D Center. He earned BS and DSc degrees in chemical engineering from the federal University of Rio de Janeiro and an MSc degree in petroleum engineering from Campinas State University.
This lecture explores the vital role that oil and gas have played and will continue to play in providing energy to the world’s burgeoning masses. This lecture will examine the urgency and challenge of extending petroleum-derived energy to more people, further into the future, with minimal environmental impact.
Ben Ebenhack is a senior lecturer in the chemical engineering department at the University of Rochester, board chair of the Access to Energy for African Development (AHEAD) Energy Corporation, and principal investigator for the sustainability and global energy systems (SAGES) project. He earned an M.S. degree in 1984 from the University of Wyoming.
Environmental Performance in the Oil and Gas Exploration & Production Industry: Assessment and Challenges
Companies need to collect and report on their environmental performances for various reasons. Efforts made at either national level, regional, or international level have been efficient but the quality of the data still needs to be improved and additional data are to be collected to meet stakeholders expectations and the need of the industry.
Emmanuel Garland is a special adviser to the health, safety, and environment vice president, at Total E&P. He earned an engineering degree from the École Centrale de Paris and a petroleum engineering degree from the École Nationale des Pétroles et des Moteurs, Paris.
Loss of drilling fluid to the formation is one of the costliest problems that drillers face during well construction. Current technology enables a comprehensive approach that includes this remediative method but gives greater emphasis to preventing lost circulation.
Fred Growcock is senior technical adviser for M-I SWACO in Houston. He earned PhD and MS degrees in physical chemistry from New Mexico State University, and BA and BS degrees in chemistry from the University of Texas at Austin.
This presentation will focus on key stimulation issues associated with gas shale reservoirs and how to determine the appropriate completion methodology.
George Waters is an engineering adviser for Schlumberger Data & Consulting Services in Oklahoma City. He earned a BS degree in petroleum engineering from West Virginia University, an MS degree in environmental engineering from Oklahoma State University, and an MS degree in petroleum engineering from Institut Francais du Petrole.
This presentation will disseminate the mechanisms of water production and their effect on production decline in horizontal wells. Key problems and challenges in developing viable water shut-off (WSO) solutions for the various horizontal well completions will also be discussed.
Keng Seng Chan is a Principal Reservoir Engineer for the Petroleum Management Unit at Petronas in Malaysia. He earned BS and MS degrees in physics from the University of Rangoon, and MS and PhD degrees in chemical engineering from the University of Florida.
This presentation will attempt to demystify many of the legends of formation damage and their evaluation. New examples will be presented of the process of understanding and avoiding damage.
Michael Byrne is principal formation damage consultant for Senergy. He earned a BSc degree in Geology and Mathematics from University College Dublin.
Calibrating Permeability with Production Logs: A Breakthrough in Carbonate Reservoir Characterization
A step change improvement can be made to the predictive accuracy of a carbonate reservoir flow simulator by using production-logging tools (PLTs) calibrated permeability to construct the geologic model. The improvement is most dramatic in carbonate reservoirs exhibiting problematic excess permeability due to fractures and vuggy porosity.
Michael J. Sullivan is reservoir surveillance coordinator for the Tengiz field in Kazakhstan. He earned an honors degree in Petroleum Engineering from Montana Tech.
This presentation will discuss the factors that affect the economic optimization of a well completion for the factory approach and how they are currently being addressed, with focus on the Rocky Mountain region of North America.
Mike Eberhard is technical manager for Halliburton’s Rocky Mountain area. He earned a BS degree in mechanical engineering from Montana State University.
This presentation will look at how the sand face completion design has impacted the Sakhalin Phase II project. Developments with Shell’s fully integrated sand failure prediction tool enabled the sand volumes to be quantified and used for the first time during completion selection in Shell. The results predicted that unmanageable sand volumes would occur upon start-up, for open hole completions with pre-drilled liners (PDL).
Mike Gunningham is the Lunskoye lead production technologist of Sakhalin Energy. He earned a 1st class degree in chemical engineering from Bradford University and an MSc degree in petroleum engineering from Imperial College.
Examining Our Assumptions – Have Oversimplifications Jeopardized Our Ability To Design Optimal Fracture Treatments?
The primary message of this presentation is that unrecognized opportunities exist to improve well profitability. Challenging our misconceptions and examining actual field production has yielded techniques to improve fracture designs, despite the failure of our simplistic models to recognize those opportunities.
Michael C. Vincent is a Consulting Engineer for Insight Consulting. He earned a Bachelor’s degree in Chemical Engineering and Petroleum Refining from Colorado School of Mines.
This presentation will show important aspects related to well control safety that have been conducted in Brazil by Petrobras that result in an almost 10-year period without a blowout event in drilling operations. This presentation will focus on research and development projects that have been conducted in Brazil on well safety especially in deepwater environment.
Otto Luiz Alcantara Santos is coordinator of the well construction area of Petrobras University, the coordinator of well control training and certification program of Petrobras, instructor of drilling technologies at Petrobras University and senior technical adviser of Petrobras. He earned a MS degree from Colorado School of Mines and a PhD degree from Louisiana State University, both in petroleum engineering.
Hydraulic fracturing is used in most of the major cased hole sand control techniques today. With more than 15 years of use in the industry it is time to assess its impact and its future.
Raymond Tibbles is a sand control adviser for Schlumberger Oilfield Services based in Kuala Lumpur, Malaysia. He earned a BSc degree in chemical engineering from Michigan Technological University.
Interpretation of permanent downhole gauge data is a new problem. Permanent downhole gauges are being applied widely now, yet there is still much to be done to capitalize fully on all the advantages they can offer.
Roland N. Horne is Thomas Davies Barrow Professor of Earth Sciences and Professor of Energy Resources Engineering, at Stanford University. He earned a PhD degree in Engineering Science and a DSc degree in Engineering, both from the University of Auckland, New Zealand.
The development of reliable inspection technology provides another key to coiled tubing (CT) reliability. Magnetic flux leakage is the most common technique for finding flaws in CT. However, research is underway to adapt 3D laser imaging NDE. Output from such techniques is directly compatible with software that can quantify defect severity in real time.
Steven M. Tipton is the Frank W. Murphy Distinguished Professor of mechanical engineering at the University of Tulsa. He earned PhD and MS degrees from Stanford University and a BS degree from Oklahoma State University, all in mechanical engineering.
Effects of Complex Reservoir Geometries and Completion Practices on Production Analysis in Tight Gas Reservoirs
This lecture will demonstrate the effects of stress dependent permeability, radial composit reservoirs, and multi-layered reservoirs on the results obtained from production analysis. The completion issues addressed will include hydraulic fracture cleanup, fracture conductivity reduction and liquid loading.
Stuart Cox is a senior technical consultant with Marathon Oil’s Technology Services organization in Houston. He earned a BS degree in petroleum engineering from the University of Tulsa.
The Role of Oil and Gas in the Energy Mix of the Next 100 Years: Shifts in Demand, Supply, and Utilization of Energy
The global production curve for oil and gas will most likely resemble a long plateau with a serrated surface, tilted towards the year 2100. Oil and natural gas--so dominant in 2004 with 63%--should still be important in absolute terms in 2100, but with a much smaller relative share (about 15%) of the total energy mix.
Wolfgang E. Schollnberger is an international energy adviser and former technology vice president of BP. He earned a PhD degree in geology from the University of Vienna.
Improving Drilling Performance by Applying Advanced Dynamics Models
Drilling dynamics models play an important role in drilling performance optimization. These models can be classified as engineering tools or research tools, depending on functionality. Case studies from disparate drilling applications around the world have demonstrated that performance can be improved by applying lessons learned from advanced dynamics models.
Mark Dykstra is a Senior Staff Well Engineer for Shell International Exploration and Production in Houston, Texas. His current focus is Drilling Efficiency Optimization. Former positions include Director of Research and Director of Product Development for Hughes Christensen, focusing on rolling and fixed cutter drilling products and including tricone bits, polycrystalline diamond compact bits, natural diamond bits, impregnated bits, eccentric reamers, expandable reamers, and casing drilling bits. Dykstra earned BS, MS, and PhD degrees in petroleum engineering from the University of Tulsa.
Recommendations for Designing Nondamaging Acid Stimulation Fluids for Oil and Gas Bearing Reservoirs
This lecture presents and discusses the chemistry of acid additives, the damage that may be caused by wrong choice acid additives, the formulation of acids, certain mineralogy concerns, and the tests required to ensure the quality of the acid pumped. Pumping nondamaging acids has applicability not only to Canadian oil and gas wells, but to all producing fields worldwide.
Malcolm Knopp is Senior Acidizing Specialist with BJ Services Company Canada. He earned a BS degree in chemistry from the University of East Anglia at Norwich, England, and has been a part-time instructor at the Canadian Petroleum Institute.
Cements and Cementing: An Old Technique With a Future?
Alternative isolation techniques have been introduced for either complementing or even suppressing the need for well cementing. Tailored cements range from basic to highly technical ones to fit almost any well requirement. The versatility and adaptability of these cement based solutions to fit well “cementing” needs make it a key element in today’s well architecture, as wells can be designed differently taking into consideration the properties of these new cementing materials.
Bernard Piot is a Technical Adviser and Cementing Project Manager in the Schlumberger Riboud Product Center. He works on short-term engineering projects aimed at extending the scope and widening the applications of current commercial well cementing technology. Piot earned an engineering degree in chemistry from Ecole Européenne de Chimie Polymères et Matériaux de Strasbourg.
This presentation discusses a stepwise approach to evaluating the potential for fines production, ways to address the issue; and appraise the overall impact on the life cycle and operating costs of the well. Several case histories are presented to illustrate how it is possible to address problems related to the movement of formation fines.
David Underdown is a Senior Adviser for Chevron Energy Technology. He earned a PhD degree in physical chemistry from the University of Houston. Underdown is current Chairperson of the API Task Force on Perforating.
As there is a global imperative to reduce CO2 emissions, this opportunity is also available to other countries with significant coal-fired electricity generation and an indigenous oil industry. This lecture includes policy background, plans by utility companies, sources and sinks for CO2, the EOR opportunity, infrastructure requirements, and engineering challenges.
David S. Hughes is Technical Head Carbon Storage for Senergy. He is a reservoir engineer with 27 years of experience. Hughes edits the online periodical Improved Oil Recovery Views. He earned a BS degree in physics from the University of Surrey.
Produced Water Management Options – One Size Does Not Fit All
This lecture describes many produced water management options using the concept of a 3-tiered water management/pollution prevention hierarchy: minimize water production, recycle or reuse, and treat and dispose. This lecture offers guidance on the factors that should be considered by company managers to select the management options that are most appropriate for a particular site.
John Veil is Manager of the Water Policy Program for Argonne National Laboratory. He earned a BA degree in earth and planetary science from Johns Hopkins University, an MS degree in zoology from the University of Maryland, and an MS degree in civil engineering from the University of Maryland. Veil served as a faculty member of the Department of Zoology at the University of Maryland. He is the lead author of the 2004 “White Paper Describing Produced Water from Production of Crude Oil, Natural Gas, and Coal Bed Methane.”
How the business risks/issues of CO2 enhanced oil recovery (EOR) project are handled can make or break a project. Understanding such risks and the measures businesses must take to quantify and minimize them will go a long way to ensure a project is both a technical and an economic success.
Ken R. Brown is Manager of the Carbon and Energy Management Group at the Alberta Research Council. He is a professional engineer with 36 years of experience in reservoir engineering, project management, production engineering, operations engineering, facilities engineering, environmental engineering, and all aspects of technical management of large multi-disciplinary teams.
This lecture focuses on the importance and value of well-defined collaborative multidisciplinary, multicultural, and integrated studies executed seamlessly over the entire upstream business units of a typical oil and gas company. It is not only essential for running a successful petroleum business enterprise, but also necessary for its long-term survival.
Yasin Senturk is a Principal Professional of Petroleum En gineering and Development for Saudi Aramco. He earned a BS degree in petroleum engineering from Middle East Technical University, Ankara, Turkey, an MS degree in petroleum engineering and an ME degree in industrial engineering both from the University of Alberta, and an MS degree in economics from the University of Oklahoma. Senturk advises Saudi Aramco Management and the Petroleum Ministry in his areas of expertise.
This presentation discusses how to avoid pitfalls in assessing artificial lift run-life performance based on concrete examples to help operators and service companies better understand the issues and be in a better position to select the best run-life measures for their particular situation in both onshore and offshore applications.
Francisco Alhanati is Director E&P at C-FER Technologies. He earned a BS degree in civil engineering from Instituto Militar de Engenharia, an MS degree in mechanical engineering from the Universidade Federal do Rio de Janeiro, and a PhD degree in petroleum engineering from the University of Tulsa.
This lecture presents several field cases of the injectivity damage mitigation and consequent well and water management strategies: water treatment for seawater flooding and produced water re-injection, disposal of produced water in aquifers, waterflood design accounting for injectivity impairment for new fields, raw-water injection, subsurface separation, injectivity with heavy oils and low consolidated sands, applications of horizontal, perforated, gravel-packed and fractured wells.
Pavel Bedrikovetsky is chairperson–petroleum at Adelaide University. He holds an MS degree in applied mathematics, a PhD degree in fluid mechanics, and a DS degree in reservoir engineering from Moscow Oil–Gas Gubkin University.
Hydraulic fracturing has been described as one of the three most significant technologies to be developed in the upstream oil and gas industry in the last 50 years. The successful application of hydraulic fracturing to mature oil and gas reservoirs is about recognizing that there is a wide range of appropriate solutions available. A number of case histories are used to illustrate the effectiveness of these techniques, when they are systematically applied.
Anthony Martin is Business Development Manager for International Stimulation. He teaches fracturing, acidizing, and sand control, both in-house and externally, to customers. Martin is author of BJ Services’ Hydraulic Fracturing Manual. He graduated from Imperial College, London, with an honors
degree in mechanical engineering and an MS degree in petroleum engineering.
In Colombia’s Cusiana and Cupiaga fields, initial well rates were disappointing, mostly because of a combination of difficult perforating conditions and significant drilling induced damage. A team was formed to determine if and how BP could fracture stimulate in the most effective manner possible. This team proposed a number of solutions for both the fields that were subsequently implemented. Issues that were addressed included coping with well deviation/azimuth, rigorous prefrac wellbore preparation, novel fracstring deployment, fracturing and an efficient remedial stacking of fracs.
Martin Rylance is a Senior Petroleum Engineer and Engineering Adviser for BP Exploration. He earned a BS degree in pure mathematics from the University of Salford. Rylance is also a fellow of the Institute of Mathematics in London.
Cutoffs in Gas Reservoirs and Their Implications in Reservoir Simulation
There is great confusion over the implementation of cutoffs in industry because of the absence of clear-cut agreed-upon values among geologists, production, and reservoir simulation engineers. Cutoffs are limiting values for petrophysical properties aiming to define productive zones across the reservoir for development.
A.A. Al-Hamadah is Supervisor of the Gas Area Studies Unit in the Reservoir Simulation Division, Reservoir Description and Simulation Department for Saudi Aramco. He earned a BS degree from King Fahd University of Petroleum and Minerals and MS and PhD degrees from the University of Texas at Austin, all in petroleum engineering.
Optimizing Asset Design – Cradle To Grave– by Bridging the Gap Between the Earth Science and Engineering Disciplines Using Mechanical Earth-Modeling Technology
As the geological and geophysical modeling work of the explorationists matures, and the subsurface picture becomes clearer, well systems design optimization is being achieved by well engineers using mechanical earth-model technology. This lecture introduces acoustics-based rock mechanics concepts, describes Chevron’s acoustics-based rock property prediction technique, and presents field application case histories for selected business units worldwide, including deepwater Gulf of Mexico, North Sea, offshore West Africa, and Asia.
Harvey E. Goodman is a staff research consultant for Chevron’s Energy Technology Company. He was appointed Chevron Fellow in October 2007. Goodman is an adjunct professor at the University of Missouri–Rolla (UMR). He was awarded an honorary professional degree in petroleum engineering by UMR, where he also earned BS and MS degrees in geological engineering.
This lecture on how a major operator has used pressure-transient analysis (PTA) over the past 20 years, particularly in expensive, deepwater developments, will enable petroleum engineers to make better choices about how they should appraise and survey their own oil and gas reservoirs.
Robert H. Hite is Principal Technical Expert and a Reservoir Engineering Adviser for Shell. He consults on PTA for Shell’s worldwide operations and is the primary reservoir engineering instructor for Shell’s well-testing classes. Hite earned a BS degree in chemical engineering from Georgia Institute of Technology and a PhD degree in chemical engineering from Rice University.
Kutubu is Papua New Guinea’s largest oil field. It came on line in 1992 and achieved peak rates in 1993 before decline began in 1994. A follow up
development campaign, along with other projects, has for 4 years completely halted the production decline. The field now appears to have a considerable remaining life of up to 2 decades. This lecture’s main conclusion is that we regularly need to go back to basics and establish whether or not our fundamental assumptions are supported by solid evidence.
Neil Williams is currently in charge of the reservoir engineering, geoscience, planning, and development of the Kutubu field for Oil Search. He earned a BS degree from Sydney University in applied mathematics, and a PhD degree in fluid mechanics from the University of New South Wales.
This lecture presents the framework used by BP to implement and manage well-integrity programs and discusses the Prudhoe Bay well-integrity-management system. Well integrity has received increasing attention from all aspects of the petroleum industry. Lessons learned from the Alaska implementation are discussed, including data-management systems and several case histories.
Joe Anders is a Senior Wells Project Engineer for BP in Alaska with more than 24 years of operational oilfield experience. He earned a BS degree in geological engineering and an MS degree in petroleum engineering. Anders also holds a patent for an enhanced-oil-recovery (EOR) process.
The prevention and remediation of several flow-assurance problems require timely knowledge about the internal-deposition conditions of pipelines, sealines, and tubings. Techniques carried out by measuring and analyzing pressure signals induced by fast flow-rate changes constitute an extremely flexible, sensitive, and easily applied methodology. The basic principles of the method are illustrated, together with case histories of onshore and offshore applications.
Alberto Di Lullo leads the Flow Assurance Technologies Program of the Engineering Department of the Eni E&P Division, which coordinates operational support, design activities and R&D projects. Alberto is also (co)author of several patents and publications.
Widespread access to detailed physical models and to low-cost, high-speed computing makes it possible to harness measurements of uncertainty to the task of improving field-development decisions of all types. This lecture illustrates the difficulties and pitfalls that can arise when history matching and prediction are performed deterministically with practical examples.
Neil Dunlop is a Director at Energy Scitech, a member of the Roxar Group, and a consultant who conducts reservoir studies. He earned an MS degree in petroleum engineering from Imperial College, London, and an MA degree in chemical engineering from Cambridge University.
This presentation draws on the application of numerical modeling, laboratory rock testing, and knowledge of the processes critical to shales and hydrate-bearing sediments to provide predictive tools for the stability of wellbores drilled in challenging formations. The lecture also touches on the application of geomechanical modeling and testing to the problem of sand-production prediction, an area of major concern to the oil industry.
Reem Freij-Ayoub is a civil engineer with MS and PhD degrees in geomechanics and rock mechanics from the University of Western Australia. She joined the Commonwealth Scientific and Industrial Research Organization to develop reactive transport models then pursued her interests in problems in petroleum geomechanics.
Prefrac Reservoir Characterization From Perforation Inflow Diagnostic (PID) Testing: “Measure Twice—Frac Once”
In an effort to enhance the deliverability potential of a tight gas well, operators sometimes overlook the “missing link” between stimulation design and the well’s post-frac production response. This presentation demonstrates that a properly designed and conducted closed-chamber PID test is a cost-effective, safe, and environmentally friendly method of obtaining critical prefrac reservoir parameters.
Robert Hawkes is Team Leader of Reservoir Services for BJ Services Company Canada. He began his career with Esso Resources. Since then, Hawkes went on to establish himself as a specialist in well-test analysis with Fekete Associates. He graduated from the Southern Alberta Institute of Technology with a diploma in petroleum engineering.
In these days of high oil prices and pressure to reduce production costs, there is an economic necessity to control, optimize, or eliminate the emulsion problem by maximizing oil/water separation. This presentation provides a summary of how emulsions form during oil production, the types of emulsions encountered, what stabilizes emulsions, and up-to-date methods for reducing emulsion-related problems.
Sunil Kokal is a PVT/reservoir fluid property consultant at the Saudi Aramco R&D Center. He is an expert in hydrocarbon phase behavior, crude-oil emulsions, and asphaltenes. Kokal earned a BS degree from the Indian Institute of Technology and a PhD degree from the University of Calgary, both in chemical engineering.
Injection of CO2 into depleted and near-depleted oil reservoirs offers the potential for increasing oil recovery while sequestering industrial emissions of CO2. This presentation examines how alternative technology designs and operating strategies may enable industry to improve CO2-EOR oil-recovery efficiencies significantly, from the traditional 8 to 12% of original oil in place (OOIP) to potentially more than 20% OOIP.
Vello A. Kuuskraa is President of Advanced Resources International. He earned an MBA degree from the University of Pennsylvania and a BS degree in applied mathematics/economics from North Carolina State University.
This presentation aims to design the concept of modeling the existing data into visualized tools to help predict the future. Engineers should use Monte Carlo simulation, decision trees, databases, expert systems, linear programming, design of experiments, and all types of artificial intelligence to state their uncertainties not as discrete values, but as continuous ranges.
Sameh Macary works with IPR Group of Companies. He is the Production Department Head and a petroleum engineering professor in the Egyptian Petroleum Research Institute. Macary earned MS and PhD degrees in production and reservoir engineering from the Azerbaijanian Institute of Oil and Chemistry.
This lecture outlines the potential threats to production and safety that oilfield scale may present if not managed appropriately and discusses the criteria for analyzing and selecting the optimum control strategy. The general approach is illustrated by several field examples on which the author has worked very closely with a number of international oil companies.
Eric Mackay is a research fellow at the Heriot-Watt University Institute of Petroleum Engineering, where his interests include the application of reservoir-engineering principles and data for better understanding of production issues. Mackay earned a BS degree in physics from the University of Edinburgh and a PhD degree in petroleum engineering from Heriot-Watt University.
Smart Completions, Smart Wells, and Now Smart Fields – Challenges Our Industry Faces and How To Overcome Them
This lecture asks what are the challenges that our industry faces in turning high-frequency data into information and knowledge that can be used to make decisions and consequently turn the decisions into action. To overcome these challenges, we have to use the technology that others have used in order to solve similar problems, successfully.
Shahab D. Mohaghegh is a professor of petroleum and natural gas engineering at West Virginia University and the founder and President of Intelligent Solutions. He earned BS, MS, and PhD degrees in petroleum engineering.
This presentation involves the critical evaluation of sand-control-screen selection, design, and performance. The proliferation of new screens and screen types has raised legitimate questions about how to select the proper sand-control screen or other device for a particular formation and type of completion.
William K. Ott is an independent petroleum consultant based in Houston and is founder of Well Completion Technology. He earned a BS degree in chemical engineering from the University of Missouri.
Construction of an innovation process, database, and measurements is essential to communicate progress to senior management and validate innovative efforts. A simple process and its execution are discussed using an example project. A method to involve producing-asset staff is also described.
Phiroze Patel is Innovation Director for earned BS and MS degrees in aeronautics and astronautics and a PhD degree in nuclear engineering.
GameChanger has been successfully enabling innovators and entrepreneurs in the Shell E&P technology centers to rapidly develop innovative ideas that are not a part of traditional incremental technology development. This presentation demonstrates how innovators throughout the Shell E&P business have transformed subsurface-technology capability since the start of GameChanger in 1996. Download (pdf)
Leo Roodhart is Manager Strategic Innovation in Shell GameChanger. He is an associate fellow of Templeton College, Oxford University. Roodhart earned an MS degree in chemistry and a PhD degree in mathematics and physics from the University of Amsterdam.
The evolution of drilling technologies in recent years has allowed operators to explore for gas and high-viscosity oil in reservoirs at shallow burial depth and ultra-deep water where reservoirs are usually formed by turbidites. This discussion includes well construction issues and presents new approaches for sand-control system selection for gas and heavy-oil exploitation, minimization of pressure drop, well segmentation, and selective control of water production.
Luis C.B. Bianco is a Senior Petroleum Engineer for Petrobras in the Well Engineering Technical Support Team at the Rio de Janeiro Business Unit in Brazil. A sand-control specialist with 20 years of experience, he has been involved in advanced completion techniques and well design for deepwater wells.
Technologies related to i-field, e-field, intelligent energy, or digital oilfields have the potential to boost ultimate recovery factors to well above 50 to 60%. This presentation examines evolving technologies and offers a roadmap for metamorphosis of asset managers and personnel resources. It will demonstrate ways to facilitate the education and training of a new generation of high-tech geoscientists.
Iraj Ershaghi is the Omar B. Milligan Professor and Director of Petroleum Engineering at the Viterbi School of Engineering at the U. of Southern California (USC). He also serves as Executive Director of CiSoft, a USC-Chevron Center of Excellence for Interactive Smart Oilfield Technologies. Ershagi earned a Bs with honors from the U. of Tehran and MS and PhD degrees in petroleum engineering from USC.
GTP Technologies, including the well-known gas-to-liquids process, finally emerge as options to efficiently convert this resource into clean, high-value fuels and chemicals. Less known are rapid advances in gas-to-chemicals (such as methanol) conversion technologies and increases in plant scales which significantly reduce manufacturing costs. There is great promise for dimethyl-ether among other derivatives. This lecture will address the role of GTP in the context of existing gas monetization businesses.
Theo Fleisch is a Distinguished Advisor for BP’s new Global Gas-To-Products Group. An expert in GTP, he earned MS and PhD degrees in physical chemistry from the U. of Innsbruck, Austria, and has worked for 27 years in technical and managerial roles for Amoco and BP.
This talk will address the background of MPD, provide recent case examples in which specific drilling-related barriers were overcome, and illustrate equipment layouts required to practice each variation of MPD from all types of rigs. The desire to reduce drilling nonproductive time and costs associated with lost circulation, narrow pressure windows, slow rate of penetration, and others are key incentives to practice MPD. The two categories of MPD, reactive and proactive, along with four variations will be presented and discussed.
Don Hannegan is a recognized expert in development of MPD technology and is a functional director for Weatherford Intl. He invented several offshore designs of rotating control devices and fit-for-purpose elastomers for rotating annulus seal elements. Hannegan is also the primary content provider for the MPD chapter in SPE’s new textbook-in-progress, Advanced Drilling Technology and Well Construction.
Increased sensitivity of senior oil company executives, board members, and investors centers around the requirements of reserves booking and reporting, including exploration potential and sub-commercial resources. Discussion will focus on the need for a reserves system that captures the total resource portfolio, the critical decision points within that system (focal points for corporate governance) and a process that provides quality control and an audit trail to ensure reporting requirements are met.
Anthony Harrison is Reserves Manager for Santos Ltd. He has spent more than 30 years in the oil and gas industry and has served in a number of technical and supervisory roles in the geoscience area and in reservoir engineering.
While even the most benign wellbore conditions can be challenging under the right circumstances, this talk will concentrate on those that are challenging to even the subject-matter experts, but also point out the issues that must be addressed and are often either overlooked, oversimplified, or not considered as significant to the task at hand.
James Heathman is a Global Technical Advisor for the Halliburton Fluids Div., specializing in cementing and conformance technology. He earned BS and MS degrees in petroleum engineering from Louisiana Tech U. and a MBA degree from Oklahoma State U.
This lecture presents development application of gas injection EOR technology to such viscous oil reservoirs where gas resource is available and the reservoir has a large development target with many high rate wells. Miscible gas EOR technology is rarely applied to viscous oil reservoirs. The presentation will show that for viscous oils, it is still possible to significantly increase oil recovery above waterflood by injecting the enriched gas in a WAG process, even if classical miscibility is not achieved.
Bharat Jhaveri is a Reservoir Engineering Advisor at BP Exploration with more than 24 years of experience that includes expertise in phase behavior and compositional modeling in addition to design, engineering, and evaluation of large-scale gas EOR projects. His work was instrumental in design of the Prudhoe Bay Miscible and Vaporization Projects. Jhaveri received a BS degree in chemical engineering from Indian Inst. of Technology Kanpur in India, an MS in chemical engineering from the Illinois Inst. of Technology Chicago, and a PhD degree in chemical engineering from Stanford U.
In addition to addressing well productivity issues and considering various completion options to modeling the coupled reservoir/wellbore/surface network system, this talk explores how uncertainties in volumetrics and capital-and-operating expenses may influence designing the total system to meet delivery targets. Several useful phenomenological correlations shed light on understanding various issues surrounding management of gas/condensate systems. It also introduces a simple screening tool to check whether cycling of lean gas is feasible.
C. Shah Kabir has more than 28 years in the oil industry, with the past 15 years at Chevron. His experiences include transient testing, wellbore fluid and heat flow modeling, and reservoir engineering. Kabir earned an MS degree in chemical engineering from the U. of Calgary.
The cost of unsuccessful first-time cementing operations, while thought to be huge, is rarely measured by operators because of a technical disconnect that can occur between drilling and production staff. This lecture details some of the generally agreed best practices for prevention of drilling nonproductive time related to setting cement plugs and fluid migration after cementing. Issues impacting long-term zonal isolation, minimum engineering design requirements, and balance between good drilling fluid performance- successful primary cementing will be presented.
Daryl S. Kellingray is a Drilling Specialist in the drilling technology unit of BP E&P Technology Group. He is BP’s Global Cementing Specialist. Kellingray’s career began in the BP Research Center in London in the area of gas migration/cement shrinkage and mixing energy effects on cement slurries. He later became involved in cementing operations in the U.K. sector of the North Sea.
Achieving a reduction in sulfur, accomplished by various upgrading processes, can have a profound impact in terms of crude price. Conversion of high-sulfur crude is becoming increasingly more attractive. This presentation offers an overview of crude quality issues and heavy-oil upgrading technologies to improve crude quality. Discussion will cover compelling and innovative options and examples of opportunities, some of which can possibly be applied within E&P, in improving crude quality while addressing traditional production issues.
Rashid Khan is an Intellectual Property Specialist and Energy Technologist for Saudi Aramco providing leadership to capture, develop, and commercialize intellectual properties upstream and downstream. Considered an international expert in hydrocarbon processing, he has served as a technical advisor to the U.S. White House. Khan earned an MS in energy and fuels engineering from Pennsylvania State U. and an MS in environmental engineering from Oregon State U. He also earned a PhD in energy and fuels engineering from Pennsylvania State U.
Upscaling describes the range of techniques used to develop the properties coarser, simpler models. Current best practice has moved away from “local” calculations to “extended-local” and “global” techniques that take advantage of the adjacent portions of the detailed reservoir description to develop more robust effective properties. Upgridding describes techniques used to design the spatial resolution of the coarser model. Examples from North America and the North Sea will be used to demonstrate the power of combining these approaches.
Michael J. King, a Senior Reservoir Engineer for BP, has shaped the company’s global reservoir modeling strategy as a technology network leader, technology advisor, and R&D project manager with expertise in heterogeneity modeling and upscaling of geologic models. He continues active research in modeling strategy. King earned a PhD from Syracuse U. with post-doctoral studies in nuclear and particle physics.
Innovative integrated reservoir modeling technology based on latest achievements in seismic processing, rock physics, integrated reservoir/facility modeling, and production optimization is presented. Significant business value has been added with the new technology applications for the optimization of infill drilling, waterflood, and facility modification programs that are supported by reservoir studies in the Gulf of Mexico, Alaska, and North Sea oil/gas fields.
Michael L. Litvak, a Reservoir Engineering Advisor for BP, has 34 years of petroleum industry experience. He has developed innovative technology for integrated reservoir/facility modeling and production optimization in the commercial reservoir simulator. Litvak earned MS degree in Petroleum Engineering from Moscow Oil and Gas University and PhD in Applied Mathematics from Academy Sciences of USSR.
Using knowledge of available cements and compressive strength enhancing agents, a new cement blend was developed that could get higher compressive strengths and better acoustical impedance in a shorter time frame while maintaining the cement density at 12 ppg and slurry-process economics. Examples of pre- and post-solution cement bond logs and economics related to non-productive time over a large drilling program will be presented.
David Mack is an Advanced Senior Production Engineer in the Reservoir and Well Performance Group with Marathon Oil. Having received a Petroleum Engineer.degree in petroleum engineering from the Colorado School of Mines, he has held various research and operational positions with pressure pumping companies in north Texas, the Rocky Mountains, Mid-Continent, and Appalachian Basin.
The recent maturing of 3D rotary steerable systems has generated renewed interest in understanding wellbore quality and its impact. The term wellbore quality is not particularly well defined, its context often misunderstood and is usually considered too complex to quantify. This talk will offer an overview of issues relating to wellbore quality, explain the issues in quantifying it, and discuss the implications of having a common industry definition.
Colin Mason, a Senior Drilling Engineering Specialist based in BP’s E&P Technology Group, began his career as an academic at the U. of Southampton and later became a network analyst for a major oil and gas distribution company and a pipeline design engineer for an international engineering consultancy. He joined BP’s Technology Center in 1997, providing engineering support to extended-reach drilling operations at Wytch Farm.
Batch drilling, in combination with high spread rates, dictates that well failures be kept to a minimum. This goal is reinforced by the extreme consequences of a hydrocarbon release at the mudline. The current presentation reviews the context, success, and developmental failures of a variety of recently introduced design advances, using specific well examples to reinforce key points.
Phillip D. Pattillo is a Distinguished Advisor with BP America in E&P technology. Since 1972, he has worked in the areas of multiphase flow and tubular and rock mechanics. Pattillo earned a BS degree in mechanical engineering and an MS degree in engineering science from Louisiana State U. and MS and PhD degrees in engineering science from the U. of Notre Dame.
Sand control is mandatory in most Campos Basin reservoirs. Since the first frac-pack job was performed in 1996, many challenges related to three areas have been overcome—best practices, unconsolidated high-permeability rock fracturing. And design and pumping questions posed due to ultra-high permeability. This presentation poses both answers and questions about frac-packs in soft rocks in deep water.
Carlos A. Pedroso, a Completion Engineer for Petrobras, is a technical advisor in sand control and stimulation. He earned a degree in chemical engineering and petroleum engineering from Federal U. of Paraná and an MS degree in petroleum engineering from Campinas U.
The most recent form of testing, formation testing while drilling (FTWD), introduces new capabilities to the drilling environment. While still in its infancy, FTWD enables new pressure transient analysis techniques to determine properties of interest to drilling, such as filtrate loss rate and depth of invasion. This talk highlights applications that have been developed, applied, and successfully demonstrated.
Mark A. Proett is a Senior Scientific Advisor for Halliburton Energy Services in the Strategic Research group. He received a BSME degree from the U. of Maryland and an MS degree from Johns Hopkins. Proett has published extensively in the area of well testing and fluid flow analysis methods.
Openhole completions have become a key component to efficient field development. Given the large number of fluid options to drill and complete these wells, careful testing and planning become paramount. Problems that can arise include invasion of solids, creation of scales or emulsions, plugging of completion assemblies, or incompatibilities of sequential fluid treatments.
Charles Svoboda, the Reservoir Drill-In Fluid Technical Manager at M-I SWACO, has 23 years of experience in drilling fluids, reservoir drilling fluid, and completions. He earned a BS in civil engineering from the U. of Illinois. Svoboda’s operational and technical positions have included Technical Manager for M-I SWACO’s European Technical Center in Stavanger.
Challenges and opportunities for Operating in Environmentally Sensitive Basins Learning from the California Experience
Smaller operators, who serve as stewards of resources in environmentally sensitive areas, have profited greatly from the benefits of advanced technologies in managing oilfields in sensitive environments. Using new technology from existing infrastructure combined with cooperative efforts between government agencies and operators, it has been demonstrated that successful development can be achieve with no or mitigateable environmental impact.
Marina Voskanian, Chief of Planning and Development with the California State Lands Commission, previously worked for Exxon, Southern California Gas Co., Aminoil, and Phillips Petroleum. She earned graduate degrees in petroleum engineering from the U. of Southern California.
Drilling with casing, an emerging technology for simultaneously drilling and casing a well, is gaining increasing acceptance in onshore applications where entire wells are drilled with casing and offshore applications where it is used to drill selected intervals. This talk reviews the current status and advantages/disadvantages in drilling more than 1,000 intervals ranging from shallow surface holes using 20-in. casing to greater than 15,000 ft with 3-½-in. casing.
Tommy M. Warren is Director of Casing Drilling Research and Engineering for Tesco. He spent 26 years with Amoco serving in operations and drilling research. Warren earned BS and MS degrees in mineral engineering from the U. of Alabama and was selected as a U. of Alabama Distinguished Engineering Fellow in 1994.