Topics for Distinguished Lecturer 2014-15 Season Announced

Drilling Fluid Influenced Magnetic Shielding of Directional Measurement Tools: Causes and Consequences

The magnetic property of drilling fluid is one of the substantial error sources for the determination of azimuth while drilling deviated wells. These errors, present in all sections, may be in the range of 50 to 200 m when drilling long, deviated intermediate sections. Therefore, these effects represent a significant cost to be mitigated. The error becomes even more pronounced if drilling occurs in Arctic regions close to the magnetic North Pole (or South Pole). The presentation shows how some drilling fluid additives affect the magnetic shielding of the downhole compass. It also shows the origin of most influential types of drilling fluid contaminants, such as swarf and metallic fines, and their effects. Similarly, it is shown that a certain degree of symmetry of the flow paths around the compass is necessary to avoid distortion of the downhole magnetic readings. Finally, guidelines are presented to minimize the negative effects of the magnetic shielding.

Arild Saasen has been a technology adviser at Det norske oljeselskap in Oslo, Norway, since January 2009. He is also an adjunct professor in drilling and well fluids at the department of petroleum engineering at the University of Stavanger. Saasen holds an MS degree from the University of Oslo and a PhD degree from the Technical University of Denmark, Lyngby. In 2012, he was awarded the Carl Clason Nordic rheology prize.

Oilfield Chemicals and Global Issues That Influence Them

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 oilfield chemicals (OFC) sales at approximately USD 30 billion by 2015. This talk hopes to bring awareness to the status of OFC use from the health, safety, and environmental (HSE) perspective; stimulate a healthy discussion; and put forth a proposal for consideration aimed at unifying global approval requirements for OFC use by all nations based on a cradle-to-grave holistic approach that is based not only on HSE compliance, but also on HSE-based best practices from syntheses all the way through production, storage, and transportation. The talk solicits and urges concept buy-in and a united campaign from global organizations connected to hydrocarbon production to globally harmonize testing protocols and approval processes for OFC chemicals.

B.R. Reddy has been with Halliburton 17 years and is currently chief scientific adviser—chemist. During this period, he has worked in cementing, conformance, drilling fluids, and long-range research covering all areas of Halliburton’s chemical research. Reddy’s job responsibilities included new product and process developments. Some of the new technologies that he has contributed to were recognized with the granting of 177 US patents. He has coauthored more than 35 SPE papers.

Perforating With Lasers: Are You Ready for the Power of Light?

Lasers are on track to provide safe, nonexplosive, damage-free perforations. Current industrial laser technology addresses efficiency, portability, and reliability issues required for successful commercial field applications on all rock types, including shale. The latest multimode configuration of fiber lasers are now capable of delivering multiple kilowatts of power from an efficient, compact laser source with excellent beam quality, reliability, and long life. They represent an enabling technology that opens the door for near-term subsurface laser applications under field conditions. Examples of remote surface field applications have been made. The application of high-power lasers for perforating could significantly reduce the primary drawbacks of traditional methods—safety and damage. Lasers can cut through steel, cement, and rock to permit fluid flow with minimal skin damage. Laser perforation concepts were proven under multiple downhole conditions. Many drilling, completion, and subsurface applications with high-power lasers are envisioned.

Brian C. Gahan is founder and president of Laser Rock Technologies, a private energy consulting firm in Cary, Illinois. He was a senior scientist and manager at the Gas Technology Institute. Gahan holds a BS degree in petroleum engineering, a master’s degree in chemical engineering, and an MBA degree in finance. He has authored or coauthored more than 40 papers.

Shale Sweet Spot Detection With Surface Seismic

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. 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. Because of their success, an abundance of gas has caused a decrease in gas price and a new economic paradigm has emerged: shale sweet spot drilling. Sweet spots result from certain geologic conditions, such as increased matrix porosity or total organic content, increased microfractures, and areas with increased brittleness. These reservoir characteristics affect the physical rock properties that, in turn, affect a passing seismic signal. The ability to locate these sweet spots before drilling significantly affects the economics associated with these plays.

Brian E. Toelle is an adjunct assistant professor at West Virginia University and an adviser in exploration and geophysics at Schlumberger. He holds BS, MS, and PhD degrees in geology and has worked in the oil and gas industry for more than 33 years. Toelle has authored or coauthored 47 professional papers, posters, and presentations and has received Saudi Aramco’s Exploration Professional of the Year Award and the Performed by Schlumberger Award.

Lessons Learned in Technology Development and Perforating Smart Wells

Developing new technology is often considered risky, misunderstood, and prone to time and budget overruns. This presentation will use a recent smart well technology development program as an example of challenges in new technology development. It will also discuss challenges of introducing new technology and pitfalls that are often encountered that perpetuate the “not in my well” attitude that is often heard when introducing new technology. Increasing numbers of smart and instrumented wells are being completed worldwide. This presentation identifies challenges and methods developed to mitigate problems associated with and to enable perforating instrumented and smart wells. It will also review the tools and techniques available to perforate these types of completions while avoiding damage to pipe external control lines, cables, gauges, fiber-optic lines, and other critical completion equipment. Discussions will cover a brief history and limitations of currently available tools and techniques.

Curtis G. Blount is a senior fellow adviser at ConocoPhillips in the Houston-based Global Well Technology group, specializing in advancing technology applied in challenging and harsh environments. He has been active in coiled tubing and well intervention research and applied technology development for more than 25 years. Blount has coauthored more than 30 technical papers and holds more than 20 patents.

Fracturing Fluids: How to Frac With Less or No Water

The US Environmental Protection Agency estimates that 140 billion gal of water are needed annually for hydraulic fracturing operations in the United States alone. While that is just a fraction of the total US water usage, the industry is becoming a lightning rod in the water use debate. Add to that the growing concern about burgeoning truck traffic on local roads and the seismic activity often blamed on high-pressure wastewater injection into disposal wells, and you have an environment ripe for regulation proliferation. Additionally, the success of these technologies in North America is raising interest to develop unconventional resources in various parts of the world where freshwater resources are not readily available. The presentation will describe technologies currently available for fracturing applications using lower-quality water, fluid systems that minimize or eliminate water, and systems based on nonaqueous liquids, or even no liquids at all.

D.V. Satya Gupta is business development director of Baker Hughes Pressure Pumping Technology. He has more than 33 years of experience in oilfield chemical product development and applications. Gupta has published more than 60 papers and holds more than 130 international and US patents. He holds a doctor of science degree in chemical engineering from Washington University in St. Louis.

Unconventional Reservoirs Require Unconventional Analysis Techniques

Rate transient analysis (RTA) has become popular over the past decade as a theoretically robust yet very practical tool for well performance evaluation, making use of continuously measured production rates and flowing pressures, which are collected as part of good production practices. With the advent of unconventional resource plays, these RTA techniques have evolved significantly. In light of these recent developments, it is easy to become lost in the details when trying to analyze unconventional reservoirs, particularly when one considers the complexities of flow behavior, pressure-dependent reservoir properties, high-pressure/high-temperature phase behavior, and the challenges of the well completion geometry. This presentation describes how and why RTA techniques evolved, starting with simple conventional reservoir systems and progressing to the complexity of fractured, ultralow permeability systems. Techniques specific to unconventional reservoirs are presented and the strengths, limitations, and applications are discussed.

David Anderson is a product manager at IHS. He has led the development of IHS/Fekete’s F.A.S.T. RTATM software and has become a recognized expert in production analysis. Anderson has authored numerous papers on the subject and has been awarded two Best Presented Paper awards from SPE. He also received SPE’s Outstanding Young Professional Award for Rocky Mountain Region in 2008. He currently serves on SPE’s Reservoir Description and Dynamics Advisory Committee.

Offshore CO2 EOR as Part of a National CCS Program: Opportunities and Challenges

The key message is that the offshore use of CO2 for enhanced oil recovery (EOR) is in its infancy. But with the adoption of carbon capture and storage (CCS) to decarbonize fossil-fueled power generation, there is a time-critical opportunity to add value to the CCS chain by adopting and maturing offshore CO2 EOR. The United Kingdom has a legally binding target to reduce CO2 emissions by at least 80% by 2050 (compared with those of 1990). To achieve this, a significant proportion of the UK’s fossil-fueled power generation is likely to be replaced by new coal and gas-fired power stations equipped with carbon capture. This opportunity is potentially also available to other countries with fossil-fueled 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.

David S. Hughes is a reservoir engineer with 34 years of experience. He works for Senergy in the UK. Throughout his career, he has specialized in the scientific, technical, and engineering aspects of EOR, including hydrocarbon and CO2 gas injection, chemical and biological processes, and in-situ combustion. He is undertaking engineering studies related to offshore CO2 storage, EOR, and low-salinity waterflooding. He holds a BS honors degree in physics from the University of Surrey.

A Holistic Approach to Understanding the Impact and Cause of Fines Production

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 turns out to be fines. Several major operating companies are now starting to notice many wells are showing increasing skins over time. One of the often cited causes is formation fines migrating into and becoming trapped in the near wellbore reservoir matrix or gravel pack or frac pack. 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? The presentation discusses a methodical approach to evaluating the potential for fines production, ways to address the issues, and to appraise the effect on the life cycle of the well.

David Underdown is a research consultant at Chevron Energy Technology Company in Houston. He has worked in sand control and formation damage for more than 40 years for Getty Oil Company, Baker Sand Control, and Arco. Underdown has authored multiple papers and holds several patents. He holds a PhD in physical chemistry.

Geologic Factors Associated With Successful Shale Gas Plays

Shale is the most common sedimentary rock-type in the world, and massive shale deposits can be found on every continent. A lithologic unit is classified as shale if it is composed of fine-grained sediments. To determine if a particular shale is viable as an unconventional hydrocarbon play, various geologic factors must be understood about those sediments. As an example, the shale’s mineralogy must have certain characteristics that will allow it to be fractured. The recent shale revolution also required the development of innovative drilling and completion technologies to transform a shale that previously acted as an impermeable seal or barrier for conventional hydrocarbon traps into a producible reservoir. This presentation outlines the key geologic factors required to have a successful shale gas play. It also highlights the fact that all shales are different, and understanding those differences is key to successful shale exploration.

David Waldo is a senior consultant with Gaffney, Cline, and Associates. During the past 7 years, he has been involved in the evaluation of shale plays in Canada, the United States, and southeast Asia. He has more than 30 years of experience in petroleum exploration and development, with a focus on the creation, evaluation, and valuation of international oil and gas opportunities. He is an honors graduate in geology from Texas A&M University.

Acid Stimulation Challenges and Solutions in Deeper Limestone Reservoirs

As oil demand increases and technology advances, deeper carbonate reservoirs are being developed, some offshore in deep water such as in Brazil’s pre-salt. These reservoirs contain mainly dolomite/limestone, having porosity variations from microcrystalline to caverns. Depending on the 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 hydrochloric acid, which is used to stimulate these wells with positive 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. An optimum stimulation can be obtained by balancing penetration and conductivity. More efficient, resistant, and friendly products and systems have been developed. Acid tunneling lateral branches have improved penetration and viscoelastic surfactants have improved acid distribution, both noticeable in improved treatment results that are illustrated in this presentation.

Gino Di Lullo is a registered engineer and holds a BSEE degree from UCP-Brazil. After training with DS in Bolivia, he worked in field, technical, marketing, and managerial positions for Schlumberger, BJ Services, Baker Hughes, and Superior Energy in the Middle East, South America, Asia, and Africa. He retired in 2013 and became an energy consultant. He holds several patents and has authored more than 50 technical papers.

Pore Scale Imaging in Black Shale: What Does the Organic Matter Look Like, and Does It Matter?

The discovery of nanometer-sized pores in the organic phases in black shale has led laboratories in the oil and gas industry to invest in electron microscopy tools. However, the researchers were confronted with the field of view vs. resolution paradox. Images that show the small pores are typically only a few tens of micrometers wide. The big question is how representative the features are. The latest technology introduced is FIBSEM, where a focused ion beam (FIB) inside a scanning electron microscope (SEM) enables 3D reconstructions with nanometer resolution. A workflow is presented in which the core plug scale mineral maps are combined with hundreds or thousands of SEM images to define the representative elements of the core plug. Extracting numbers from images is an important part of this workflow. Examples are shown in the Eagle Ford, Marcellus, and Niobrara shales.

Herman Lemmens is a technology manager at FEI in the Netherlands. His role is translating the needs for pore scale imaging in the oil and gas industry into product specifications for new electron microscopy tools. Lemmens’ primary areas of interest are imaging of porosity in the organic phases in shale, integrating imaging at different length scales, and relating mineral textures to fracturing efficiency. He holds a PhD degree in physics from the University of Antwerp.

Multiscale Discussions on Gas Storage and Transport in Organic-Rich Shale

It is now well documented that resource shales consist of pores with small volumes contributing to the storage of hydrocarbon fluids. Physical chemistry of fluids under confinement in such a small space could lead to various equilibrium thermodynamic states under subsurface conditions; consequently, phases could change and critical properties could shift unpredictably. This presentation will discuss the pressure/volume/temperature behavior of confined hydrocarbon fluids using atomistic modeling and molecular simulations and comparisons with the classical fluid. The behavior is different mainly because of pore-wall-dominated intermolecular forces. The molecular forces also play a significant role on the fluid transport and could lead to potential non-Darcian flow effects during the production. The molecular transport effects on flow will be introduced using mesoscale lattice Boltzmann simulation of gas dynamics in nanocapillaries. The presentation will conclude with a demonstration on the effect of fluid behavior under confinement on shale hydrocarbon in-place calculations.

I. Yucel Akkutlu is an associate professor of petroleum engineering at Texas A&M University. He has been participating in industry-led research on development of new laboratory techniques and protocols in quantifying fluid storage and transport processes in organic-rich shales coupled with geomechanics. Akkutlu’s current research is on fluid thermodynamics and capillarity in nanoporous materials. Akkutlu is a chemical engineer and holds a PhD degree in petroleum engineering from the University of Southern California.

Next Generation of Energy-Efficient, Low-Water Usage Heavy Oil Recovery Methods

In-situ heavy oil recovery from oil sand formations has become economically successful in the past 2 decades. Inventions and developments of recovery processes using steam injection such as cyclic steam stimulation and steam-assisted gravity drainage have contributed to this success. However, the major weak points of the steam-based processes are their high energy consumption, large emission of greenhouse gases, and large consumption of fresh water. The compound effects of solvents and heat on the viscosity of heavy oil can provide heavy crude production rates that could be equivalent to or higher than those from the injection of steam alone. Solvent-assisted processes can also contribute to in-situ upgrading. Numerous schemes to use solvent and heat have been invented and patented. How-ever, there is a lack of basic phase behavior data and mechanistic knowledge about the solvent/heat assisted recovery processes. This talk will provide quantitative mechanistic insights into the processes.

Jalal Abedi is a professor of chemical and petroleum engineering at the University of Calgary. He leads a phase equilibrium research facility and a research group that is involved in experimental measurements of heavy oil/solvent/steam phase equilibrium and equation of state modeling and simulation of transport processes. Abedi holds the Natural Sciences and Engineering Research Council of Canada Industrial Research Chair in solvent enhanced recovery processes. He has authored or coauthored more than 100 peer-reviewed papers.

Comparing Formation Evaluation Measurements Made Through Casing With Openhole Logging Measurements

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 the more basic measurements in either open or cased wellbores. The increasing numbers of horizontal wells, especially in unconventional reservoirs, has led to a trend whereby 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 because of cost or risk factors associated with deployment. The introduction of pulsed neutron capture measurements nearly 50 years ago provided some of the first opportunities to conduct formation evaluation in cased wellbores. Over the years, new cased hole measurements have been introduced to make measurements previously only observed in open hole.

James Hemingway started at Schlumberger in 1980 and has held various petrophysics and engineering positions since 1982. He moved to Paris in 2001 as a new technology adviser and has been based in Houston since 2010 as a petrophysics adviser focusing on unconventional resources. Hemingway has been heavily involved in reservoir monitoring of enhanced oil recovery operations using techniques designed for use in cased wellbores. He holds degrees in chemistry and chemical engineering.

Diamonds in the Noise—Treasures Lurking in Acoustic Data

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 characterization, permeability, wellbore stability, hole size, cement evaluation, production optimization, brittleness maps, and much more. This presentation will present some of the many gems that can be mined from acoustic waveform data. Included is a brief review of the types of acoustic tools appropriate for each application as well as tips for optimizing data acquisition.

Jennifer Market is the borehole acoustics manager at Senergy, an international software and consulting company. Her role involves acoustic data processing and interpretation, along with development of software and new application. Market also provides industry training seminars to widen the understanding of acoustic data acquisition and applications. She has 15 years of experience in borehole acoustics, working in a service company to develop acoustics tools and applications.

Shale Well Performance Metric: We “Shale” Succeed

This presentation engages several completion and operational issues that affect the long-term performance of horizontal shale wells, in addition to traditional completions. These observations are based on a significant population of wells evaluated for their completion effectiveness, reservoir quality, and other performance metrics. The presentation demonstrates that several common practices may not have the expected outcome unless mitigating measures are employed. It documents the probability that the preventative measures can be beneficial. The fundamental goal and specific point is that relatively minor changes in operating practices have significant long-term benefit and consequences.

James Crafton is the founder of Performance Sciences in Colorado. He holds a master’s degree from the University of Oklahoma and a PhD degree in petroleum engineering from the University of Tulsa. Crafton developed the reciprocal productivity index technique, a practical method for the evaluation of producing shale, oil, gas, and coalbed methane wells. Crafton is chair emeritus of the Distinguished Lecturer Committee and was named a Distinguished Member in 2008. He holds several patents.

LNG—Changing Quickly

The liquefied natural gas (LNG) industry continues to diversify. New LNG markets are appearing, and trading patterns continue to evolve. Shale gas has already affected this industry and its full effects have yet to be seen. Floating LNG (FLNG) attracts strong interest. This capital-intensive industry requires long lead times and special contractual relationships between sellers and buyers. The technologies are undergoing change and improvement. The LNG carriers are becoming more numerous and larger. LNG import terminals are appearing in many new countries. Also, previously used commercial arrangements are evolving. Base-load plants are being constructed in new regions, and the traditional LNG supply-demand pattern is becoming increasingly complex. This presentation illustrates some key developments in the world of LNG. Important changes in the trade required investment levels and the technology are described in this rapidly growing and changing business.

John Morgan is an executive of John M. Campbell/PetroSkills. He has published extensively on sour gas treating, LNG training, sulfur recovery, CO2 EOR and treating, materials of construction, and cryogenic gas processing. Morgan consults for both North American and international clients. He holds a BSc degree in chemical engineering from London University and an ME degree in chemical and petroleum refinery engineering from the Colorado School of Mines. He is a registered professional engineer.

Hydraulic Fracture Complexity: Insights From Geology, Modeling, and Physical Experiments

The shale gas revolution, ushered in through the Barnett Shale development in Texas, demonstrated the potential of multifracture horizontal wells. A close companion with hydraulic fracture placement technology was fracture diagnostic technology. The ideas around hydraulic fracture complexity exploded with the widespread application of microseismic monitoring. This talk will use natural fracture examples and create complex fracture geometries using numerical fracture propagation modeling and scaled laboratory experiments. Evidence of stress shadow effects is illustrated for natural fractures, and the consequent effect in hydraulic fractures is demonstrated through modeling. Cemented natural fractures are proposed as primary pre-existing flaws with which hydraulic fractures might interact, and the factors influencing this interaction are illustrated. Scaled laboratory experiments simulating hydraulic fracturing in naturally fractured reservoirs illustrate the range of fracture interaction geometries that might occur in the subsurface. Lessons learned from this integrated approach to fracture complexity characterization can help guide well planning, geologic data collection, and hydraulic fracture optimization efforts.

Jon E. Olson is an associate professor in petroleum and geosystems engineering at the University of Texas at Austin. He also serves as sole proprietor of  JEO Associates, a petroleum consulting and software company. Olson holds BS degrees in civil engineering and earth sciences from the University of Notre Dame, and a PhD degree in geomechanics from Stanford University. He has published extensively on geomechanics and structural geology.

Shale Plays: How Technology, Governments, Regulators, Academia, and the Public Have Changed the World’s Energy Supply and Demand Equation

The global shale revolution is just beginning. Production from US shale reservoirs has increased from 2.5 Bcf/D to more than 25 Bcf/D since 2007, illustrating the viability of this prolific new source of long-term gas supply. Other countries will undoubtedly use the knowledge developed in North America to jump start their own shale plays. Although technical advancements are largely responsible for unlocking the potential of shale gas, the industry’s coordination with a broad set of stakeholders arguably have equal, and perhaps more, influence on the implementation of new shale developments. As such, they will increasingly affect our industry’s ability to develop these resources. This presentation focuses on key technological advancements that drive shale gas development, but also the important aspect of how the industry is working with governments, regulators, academia, and the public more collaboratively to maximize the immense benefits from this opportunity while fostering the use of best practices.

Joseph H. Frantz Jr. is the vice president of engineering technology at Range Resources. He started working on shale reservoirs in 1984 and has been involved with studies on many shale fields across the United States. Frantz has authored or coauthored more than 40 publications and taught an industry school on developing shale reservoirs. He holds a BS degree in petroleum and natural gas engineering from Pennsylvania State University.

Holistic Diagnostic Approach: The Key to Successful Conformance Engineering

Excessive water production is a widespread problem that can detrimentally affect the profitability of hydrocarbon-producing reservoirs and limit their economic life. A wide variety of mechanical and chemical technologies have been implemented throughout the years for controlling unwanted fluid production, referred to as conformance technologies. The main objective of this presentation is to provide an overview of (1) conformance technology development in recent years, and (2) how proper diagnostics and candidate selection are the keys to high success ratios with these types of treatments. An overview of how water control technologies have evolved in recent years is presented. Several case histories are discussed, highlighting the problem identification stage before execution, including different types of reservoirs, wellbore completions, and water production mechanisms, among others. It is also important to understand that each technology has limitations because conformance treatments are often applied in reservoir/wellbore conditions outside of their operating capabilities.

Julio Vasquez is a petroleum engineer working as a conformance global product champion for Halliburton’s production enhancement product service line. He is responsible for providing technical support to the company’s global operations related to water and gas shutoff and for the development of strategies for business, research and development, and training activities for conformance. Vasquez holds 10 US patents and has authored more than 50 SPE publications. He holds BS and MS degrees in petroleum engineering from the University of Oklahoma.

Assuring an Adequate Safety Culture in Production Operations

Everyone agrees that 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 that it 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.

Ken Arnold has almost 50 years of industry experience, with 16 years at Shell and 25 years as founder and CEO of Paragon Engineering Services. In 2007, he formed K Arnold Consulting. In addition he works as a part-time senior technical adviser for WorleyParsons. He is the coauthor of two textbooks and more than 50 technical articles on safety management, project management, and facilities design. He has twice served on the SPE Board of Directors and is currently the vice president of the Academy of Medicine, Engineering and Science of Texas and a member of a National Research Council committee charged with developing a framing report on safety culture in the offshore industry.

Understanding and Checking the Validity of PVT Reports

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 behavior and the transport properties of the produced fluid. These fluid properties can be obtained from pressure/volume/temperature (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.

Klaus Potsch is a retired senior expert from OMV and a consultant for fluid studies. For the past 4 years, he has been a guest lecturer in reservoir fluids and their modeling at the Mining University of Leoben, Austria. Potsch holds BS and MS degrees in physics and a PhD degree in mechanical engineering from the Technical University of Vienna.

Formation Damage Matters—Sometimes

This lecture will explain that understanding the effect of formation damage is critical to successful well design. It has long been recognized that formation damage during drilling, completion, production, well intervention, and injection has a serious effect on well performance, field life, and value. This lecture provides some insight into new understanding, modeling, and theories on the effect of formation damage. Specific cases in which damage is not important or is extremely important are explained. The concept of using damage to help with drilling low-pressure reservoirs and the real effect of damage in long wells will be discussed. The difference between skin factors and formation damage will be explained, and the traditional reliance on skin to help explain and predict well performance will be discussed. The lecture will advocate the use of modern computational power to solve complex physical challenges.

Michael Byrne is the global technical head of formation damage at Senergy in Aberdeen. A graduate of University College Dublin, he has worked in the oil industry for 25 years and has spent 24 years evaluating formation damage and sand control challenges. Byrne has presented training courses and served as a consultant to major oil companies worldwide. More recently, he has pioneered the use of computational fluid dynamics for well inflow modeling and has several patents in application.

Tight Coalbed Methane—A Giant Worldwide Resource: How Do We Produce it? (Challenges and Solutions)

The development of coalbed methane (CBM) has been limited to moderate- to high-permeability reservoirs. However, a significant resource of natural gas exists within low-permeability coals. Worldwide, CBM resources are estimated to range from 3,500 to 7,000 Tcf. As of 2010, however, only 60 to 70 Tcf of CBM reserves were proved. Vast CBM resources are untapped. Because of the coal depositional process and the nature of gas storage and transport mechanisms, a large percentage of CBM exists in low-permeability, or tight, coals. Horizontal drilling and enhanced CBM techniques have been successful in recovering gas from tight coals, but with limited commercial success so far. Better understanding of coal geology and geomechanics will lead to identification of sweet spots that can be successfully developed. Advancements in horizontal drilling technology and potentially enhanced CBM technology will reduce development costs and facilitate commercial development. Research and development is required to advance these technologies.

Michael Zuber is a technical adviser for Schlumberger Asia Area. He is a mentor for the emerging unconventional gas, shale, and CBM business in Asia. From 2003 to 2007, Zuber was vice president of reservoir engineering at CDX Gas. He has authored numerous publications relating to evaluation of CBM reservoirs. Zuber holds a BS degree from Marietta College and an MS degree from Texas A&M University, both in petroleum engineering, and an MBA degree from the University of Pittsburgh.

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 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 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. 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 and inspection requires sound engineering practices 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.

Mohsen Achour is leading the corrosion, inspection, and materials group of the Global Production Excellence Division of ConocoPhillips. He holds a PhD degree in chemical engineering and materials from Oklahoma State University and an adjunct professor honorary title from Ohio University Institute of Corrosion and Multiphase Technology Center. Achour has published more than 60 technical papers and holds patents in the areas of transport phenomena and corrosion.

Managed Pressure Drilling: Experiences and Way Forward

Managed pressure drilling (MPD) has been available for more than a decade now. The common thinking is that MPD has the potential to be a widely used enabling technology in the future, but it 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 effective project engineering and management and strict health, safety, and environment management. Confusion about MPD’s application may also have contributed to its slow acceptance rate. This presentation will highlight some of the case studies, as well as lessons learned from the MPD implementations. Sharing the true MPD benefit will enhance the adoption of this enabling technology on a wider scale.

Muhammad Muqeem is a drilling engineering specialist at Saudi Aramco. He has more than 20 years of international expertise in underbalanced/managed pressure drilling, wellbore hydraulics, and multiphase fluid flow in porous media. Muqeem has extensive experience in horizontal, multilateral wells including coiled tubing and sour drilling. He has authored and coauthored several SPE papers. He holds a PhD degree in petroleum engineering from the University of Alberta.

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 blowout 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 farther 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 is crucial to avoid gross errors. Several examples will be used to illustrate the benefits of directional data quality control.

Nestor Eduardo Ruiz is LAS area manager for Gyrodata. He holds an electronic engineering degree from the University of Buenos Aires in Argentina. Ruiz 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 planned the trajectories of the first horizontal wells drilled in Argentina, which also included blowout well experience.

A 30-Year Perspective on Use of Dynamic Well Test Analysis

Dynamic well test analysis is a family of techniques that petroleum engineers use to characterize wells and reservoirs. As with any technology, users need to understand why they do it, how it can be improved, and how it fits into the wider perspective. Overall, the possible rationales for testing have not significantly changed over the past 30 years, but the ever-increasing economic pressure for cost efficiency competing with the improved ability to deliver quality interpretations has changed the relative importance of the rationales. Three examples of improved dynamic well testing are optimal value testing, permanent downhole pressure gauges, and the new rate transient concepts being used for unconventional wells. These technologies are safer and cheaper yet deliver better decisions. These case studies on how a major operator used pressure transient analysis during the past 30 years will enable petroleum engineers to make better choices about how they should appraise and survey their own reservoirs.

Robert H. Hite retired as Shell’s principal technical expert on well testing in 2008. He consulted for Shell’s worldwide operations and was the primary reservoir engineering instructor for well testing. Since 2008, he has continued well test consulting for a wide range of international companies. Hite holds a bachelor of chemical engineering degree from Georgia Tech and a PhD degree in chemical engineering from Rice University. Over a 32-year career, besides well testing, he worked on a wide variety of reservoir engineering problems including reservoir simulation, steamflooding, and appraising and developing deepwater Gulf of Mexico reservoirs.

Moving the Frontiers in Artificial Lift Technology in Mature Field Operations

Nearly 40% of today’s oil production comes from mature fields, and this proportion is increasing. A significant portion of operating costs in brownfields is related to lifting costs and maintenance of artificial lift equipment. Often additional costs for workovers arise because of suboptimal corrosion control, when sand production becomes an issue (unconsolidated reservoirs), or as the result of a long waterflood 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. To combat this loss of reserves and valuable energy resource, a number of measures must be taken. 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.

Siegfried Muessig is a technology and quality manager at RAG, Vienna, Austria. He holds a diploma and a PhD degree in physics from the University of Karlsruhe, Germany. Throughout his career Muessig was dedicated to innovative technologies when conventional solutions failed. He has published 35 technical papers and holds six patents. Muessig  is a guest lecturer at the University of Leoben, Austria.

Diamond: A Driller’s Best Friend

A 250-year history of scientific development preceded the first synthetic diamond. Finally, in the 1950s, 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 nonferrous materials. Two decades later, in 1973, the polycrystalline diamond compact (PDC) bit was invented, but it took another 7 years of development before it established itself as the new drilling product for oil and gas wells. Early this century, following another 20 years of innovation, peaking with the invention of a thermally stable PDC, the PDC bit market finally exceeded that of the roller-cone bit. 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?

Terry Matthias holds a BS degree 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 beginning of the successful commercialization of PDC bits. For the past 33 years, he has worked on PDC bit and cutter design and development. He led the team that invented an industry-changing and award-winning thermally stable PDC.

Topics for Distinguished Lecturer 2014-15 Season Announced

01 July 2014

Volume: 66 | Issue: 7