bluuebunny/crossref_metadata_2025_split huggingface dataset:
Overview: Field Development Projects (September 2007)
Authors: Cunha J.C. 
Published: February 2015

Recently, during the Second International Oil Congress and Exhibition in Mexico, I had the opportunity to attend a roundtable discussion on "Global Trends in Deepwater Development." The event, held in Veracruz, had representatives from some of the major players in deepwater field development, and most talks and discussions focused on the challenges, concerns, problems, and rewards expected in coming years in the deepwater and ultradeepwater environments.
In the Gulf of Mexico alone, it is expected that new oil reserves in excess of 45 billion bbl will be found in the near future. However, improved economic development of those reserves will be achieved only with state-of-the-art technologies in all phases of the project. Efficient field development must take into account simultaneously the constraints in well drilling, production scheme, subsea equipment, and reservoir management. Because only limited information is available in the earlier stages of the development plan, a structured way to handle the risks involved also must be implemented.
Establishing a field-development strategy under very-high-uncertainty conditions appears to be the rule in most recent deepwater projects. In the round-table discussion in Veracruz, the panelists seemed to be conscious of the huge challenges ahead and, at the same time, excited and optimistic about the future development of fields that just a few years back were deemed impossible ventures. What do you think? I invite you to read the featured articles presented this month and reach your own conclusions. Enjoy.
Field Development Projects additional reading available at the SPE eLibrary: www.spe.org
SPE 101286 "Exploration Potential of Sinuous (Channel-Like) Events in Late Cretaceous of Al-Khafji Field, Middle East" by Kalyan Chakraborty, SPE, Kuwait Gulf Oil Company, et al.
SPE 107387 "The Challenges of Developing a Deep Offshore Heavy-Oil Field in Campos Basin" by F.P. Figueiredo Júnior, Petrobras, et al.
Available at the OTC Library: www.otcnet.org
OTC 18538 "The Dalia Development Challenges and Achievements" by D. Picard, Total E&P Angola, et al.
Interview with 2009 SPE President Leo Roodhart
Authors: Roodhart Leo , Donnelly John 
Published: February 2015

President's interview
Leo Roodhart is Head of Strategic Innovation at Shell International. With Shell since 1980, he has worked in R&D, production engineering, business development, and innovation.
Roodhart has been active in SPE for more than 25 years, most recently Director for SPE's North Sea Region, Chairperson of the Board Committee on Technical Programs and Meetings, and a member of the Board Committee on Finance and Administration. His contributions to the Society, at the local and international levels, have emphasized encouraging technology innovation. Roodhart has actively contributed to the SPE Forum Series, serving on Forum steering committees and as a member and as Chairperson of its Implementation Committee for the Eastern Hemisphere. He also has chaired the Forum Series Coordinating Committee. Roodhart has served as both Program and Section Chairperson for SPE's Netherlands Section. He has served on the program committee for Europec and on the 2001, 2003, and 2005 Offshore Europe executive committees. Roodhart chaired the first two Netherlands Applied Technology Workshops (ATWs) on Mature Reservoirs and has served on or chaired many Forum and ATW committees. He has been a member of the Distinguished Lecturer Committee and was an SPE Distinguished Lecturer during 2007–08.
Roodhart is an Associate Fellow at Templeton College, Oxford University, on Strategic Innovation. He earned an MS degree in chemistry and a PhD degree in mathematics and physics from the University of Amsterdam.
What would you like to accomplish during your term as SPE President?
Each SPE President is just one of the links in a long chain of Presidents, each with his or her own aspirations; together they built SPE into what it is now. Even if it would be possible, and it is not, for a President to make big changes in the one year he/she has, it is probably not a good idea.
That said, the SPE Board of Directors developed some time ago a Long-Range Plan to guide our Society, which is updated regularly. The current Long-Range Plan identifies key strategic issues, such as turning SPE into a truly global society; engaging young people, particularly inducing students to come select careers in our industry; and tackling such global issues as reserves definitions, capture and sequestration of CO2, and improving the industry's image.
Barnett Shale Showcases Tight-Gas Development
Authors: Parshall Joel 
Published: February 2015

Horizontal drilling and continuing advances in hydraulic fracturing have made the Barnett Shale formation of north Texas one of the great recent success stories in gas production and a showcase for tight-reservoir development technologies. Yearly production from the north-Texas Barnett Shale, officially called the Newark East field by the Texas Railroad Commission, grew to 1.1 Tcf of gas equivalent in 2007, making it second in size only to the Panhandle-Hugoton field among US producing gas fields. Cumulative Barnett production from 2000 onward now exceeds 4 Tcf.
The north-Texas Barnett Shale extends over 5,000 square miles and at least 17 counties, with the core areas lying within Denton, Tarrant, and Wise counties. While the formation can be found at depths as shallow as 3,000 ft in some areas, it primarily appears between 7,000- and 9,000-ft depths. Pay-zone thickness ranges from 100 to 1,000 ft and averages 300–500 ft.
Notably, shales like the Barnett once were seen mainly for their role as barriers that trapped hydrocarbons in other rock or were useful for containing secondary-recovery repressurization or fracturing operations. They were seldom considered producible formations because of shale's low permeability, making it difficult for fluids to move within the rock and, thus, for hydrocarbons to flow to the wellbore. Matrix permeability in the Barnett is extremely low, ranging generally between 10–7 and 10–9 darcies. Partially improving the permeability is the presence of interbedded silt- and sand-sized particles.
The Barnett Shale was believed to be hydrocarbon-rich even before a discovery well was drilled by Mitchell Energy in 1981. Nonetheless, development activity had to wait another decade or more and did not attain any momentum until the late 1990s.
With the extremely tight formation, the use of fracturing to break up as much reservoir rock as possible was a necessity. At first, Mitchell's development strategy consisted of drilling vertical wells completed with massive hydraulic fracturing treatments, using crosslinked gels to transport from 1 to 1.5 million lbm of sand proppant in the formation. In 1997, with the success that another operator had experienced with slickwater fracturing (water-frac) technology in the east-Texas Cotton Valley formation, Mitchell began to apply slickwater fracs in the Barnett, with impressive results.
Multiple-Layer Completions for Treatment of Multilayer Reservoirs
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 112476, "Multiple- Layer Completions for Efficient Treatment of Multilayer Reservoirs," by Gary Rytlewski, SPE, Schlumberger, originally prepared for the 2008 IADC/SPE Drilling Conference, Orlando, Florida, 4-6 March. The paper has not been peer reviewed.
A new method of completing multiple-layer formations has been tested successfully. This new method places sliding-sleeve valves in the casing that are opened one at a time to fracture layers independently without perforating. Completions using these casing valves have a unique design feature that allows a theoretically unlimited number of valves to be placed in a single well without incremental reductions to the inside diameter (ID). This near fullbore feature allows normal cementing operations to be performed with a special cement wiper plug.

Introduction
The US and Canadian tight-gas market is deploying new methods to stimulate multiple-layer reservoirs efficiently. The treat-and-produce (TAP) completion system has been developed to allow efficient treatment of individual layers in cemented cased-hole completions. TAP completions use special casing valves that isolate individual layers. The TAP valves are near full bore and do not require incremental ID reductions, thus allowing normal cementing operations. The TAP valves also have unique helical ports that align to any preferential fracture plane, regardless of the orientation of the valve in the casing string. These ports ensure that a single bi-wing fracture plane is initiated from the wellbore. Fracture-initiation pressures with TAP valves are expected to be comparable to openhole fracture-initiation pressure or be lower.

The Main TAP Valve
The main TAP valve is a sliding-sleeve valve with several unique features that enable it to open selectively one valve at a time and isolate previously treated layers. There is a C-ring in the main TAP valve that, when squeezed by a piston, reduces in size. The C-ring originally has the same ID as the valve, but when reduced in size, the C-ring becomes a seat on which the next ball or dart can seal. Fig. 1 shows a cross section of the main TAP valve and the C-ring in the run-in-hole position. The piston that squeezes the C-ring (the magenta-colored component in Fig. 1) is controlled by the pressure in a control line connected to the TAP valve below it. When the lower TAP valve is opened, the port to the control line is opened to the ID fluid. The control line, which was at atmospheric pressure, now has bore pressure. The upper TAP valve receives the bore pressure through the control line and ports it to the C-ring piston. The C-ring piston has two atmospheric chambers. When the bore pressure floods one of these atmospheric chambers, the C-ring piston moves and squeezes the C-ring and is able to catch the next ball or dart pumped down. When the dart lands on the C-ring seat, it creates a seal, and pump pressure pushes the sleeve open.
Technology Focus: Wellbore Integrity, Sand Management, and Frac Pack (September 2008)
Authors: Goodman Harvey E. 
Published: February 2015

Technology Focus
This year's focus is on the completion. A paper on near-wellbore modeling of sand-production behavior provides well engineers a glimpse into the world of cutting-edge rock-failure forecasting. The paper provides engineering practitioners valuable insight into the challenge of predicting produced-sand rates on a fieldwide scale.
A second paper incorporates sand failure and produced-solids-transport fore-casts with the effects on surface facilities and production by use of a probabilistic approach to manage the uncertainties. This work provides a framework that may be used to move innovative reservoir- and production-systems failure models to the fieldwide level, which is necessary for asset management. The goal is to characterize the asset-development-plan cycle from appraisal through abandonment.
A third paper presents a possible solution to the proppant-flowback problem associated with screenless frac-pack completions. The approach involves resin coating of the proppant during pumping, and a convincing argument is presented supporting induced-fracture-conductivity preservation after placement. For deepwater completions, this issue can be extraordinarily expensive and is a very real concern when evaluating risk in completion-design alternatives.
A common theme among these papers deals with the challenge of scaling up laboratory learnings to field-development practice. Today's multidiscipline-team approach to field development can provide the connection needed to foster an awareness of the effect of diverse laboratory-measurement data on asset-development viability.
Wellbore Integrity, Sand Management, and Frac-Pack additional reading available at the SPE eLibrary: www.spe.org
IPTC 11472 • "Mechanical-Earth-Model Calibration for Sanding-Potential Estimation: A Case Study From the Tombua-Landana Development in Angola's Deepwater Block 14" by Peng L. Ray, SPE, Chevron, et al.
SPE 109662 • "Enhanced Mechanical Earth Modeling and Wellbore-Stability Calculations Using Advanced Sonic Measurements—A Case Study of the HP/HT Kvitebjorn Field in the Norwegian North Sea" by Anke S. Wendt, SPE, Schlumberger, et al.
Near-Wellbore Modeling: Sand-Production Issues
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 109894, "Near-Wellbore Modeling: Sand-Production Issues," by Guillaume Servant, IFP; Philippe Marchina, SPE, Total; and Jean- Francois Nauroy, IFP, prepared for the 2007 SPE Annual Technical Conference and Exhibition, Anaheim, California, 11-14 November 2007. The paper has not been peer reviewed.
Sand production in an oil or gas well can cause operational difficulties, but it contributes to production enhancement by improving the well inflow performance. To assess the relative magnitude of those effects and to optimize the well completion and operation, a quantitative forecast of the expected amount and rate of sand production must be made. This forecast requires a correct description of all the mechanisms involved in sand production, sand transport in particular. The proposed numerical method considers that the geomechanical problem (rock failure) interplays with the transport of sand. Equilibrium equations that control rock failure (solid mechanics) and sand transport (fluid mechanics) are solved simultaneously by an iterative coupled scheme at the wellbore scale.

Introduction
Sand production causes production problems and can generate safety and environmental hazards. However, it can increase the inflow performance of the well. Therefore, the option of installing downhole sand-control equipment may not always be the best economic solution for the project.
Heavy-oil reservoirs can benefit from allowing sand to be produced with the oil. This technique, known as cold-heavy-oil production with sand (CHOPS), allows higher production rates than conventional techniques. Again, the productivity and ultimate delivery of the well will depend on the amount of sand produced. Therefore, the ability to anticipate the sand-production mechanisms in terms of sand rate and volumes, and anticipate sand-producing patterns in the reservoir, is required for optimized development of such fields.
Two mechanisms contribute to sand production: rock failure (through which freed sand grains are generated) and transport of those free grains by the effluents into the wellbore and up to surface. Most current sand-production-risk models concentrate on the rock-failure analysis and, as such, can determine only the conditions for the onset of sand production. In the proposed model, the rock-mechanical aspects are coupled to the sand-transport problem. Therefore, interaction between the solid matrix and the slurry flow can be analyzed and translated into quantitative sand production. Paralleling development of this numerical model, a series of sand-production experiments was carried out in a purpose-built laboratory apparatus with the objectives of understanding the sand-production processes in uncemented reservoirs better and providing high-quality data sets for calibrating the model.
Discussion of Climate Changes Everything: The Coming Revolution in the Energy Industry
Authors: Holliday G.H. , Davis Kerry , Thorogood John L. , Simon A.J. 
Published: February 2015

Discussion
Editor's Note: JPT received several letters regarding Joseph Stanislaw's Guest Editorial in the June issue on "Climate Changes Everything: The Coming Revolution in the Energy Industry." Excerpts of some appear below.
To the Editor:
I found the June 2008 Guest Editorial authored by Joseph Stanislaw interesting, but not necessarily believable. Like so many climate change articles, the author combines the issue of climate change with energy independence. I am neither an atmospheric physicist nor a meteorologist, but I have read extensively on climate change. Stanislaw concludes that anthropogenic greenhouse gasses, e.g., CO2, cause increased global temperature. He supports that position by referring to an Intergovernmental Panel on Climate Change (IPCC) report. My reading convinces me that the IPCC conclusion is based on computer simulation using wholly inadequate programs. The research conducted by Dr. Willie Soon (Horner 2007, Fig. 3, 146), demonstrates no correlation between CO2 and temperature change. Dr. S. Fred Singer, in personal communication (2008), states that CO2 is a lagging indicator of climate change and this lag is on the order of 600 years.
Interestingly, on 23 March 2008, the Hadley Climate Research Unit in Britain, the NASA Goddard Institute for Space Studies in New York, the Christy Group at the University of Alabama, and Remote Sensing Systems Inc. in California reported that global temperatures decreased 0.7°C during 2007. These measurements could be interpreted as a sign of global cooling rather than global warming.
Stanislaw's discussion regarding the need for energy research is on target. We need energy to sustain our standard of living and help emerging countries with their energy needs. But, justifying this research on the basis of questionable climate prediction is wrong. G.H. Holliday

Reference
Horner, C.C., 2007. The Politically Incorrect Guide to Global Warming and Environmentalism, 146. Regnery Publishing Inc.
Interview with 2010 SPE President Behrooz Fattahi
Authors: Fattahi Behrooz , Donnelly John 
Published: February 2015

President's interview
Behrooz Fattahi is coordinator, Heavy Oil Development, Aera Energy, a California E&P company jointly owned by affiliates of Shell and ExxonMobil. He began his industry career in 1977 and subsequently worked as a reservoir engineer, reservoir-engineering manager, and team leader for Osco/Shell International, Shell Western E&P, Shell Offshore, and Shell affiliate CalResources. Before joining the petroleum industry, Fattahi conducted research for the US National Aeronautics and Space Administration (NASA) and the US National Science Foundation and taught courses in fluid dynamics and solid mechanics at Iowa State University. He is a past member of the American Institute of Aeronautics and Astronautics and the American Association of University Professors.
Fattahi has served on the SPE Board as director of the Western North America Region, and as vice president, Finance. Additionally, he has been chairman of the SPE Continuing Education Committee, a member of the SPE President's Learning Initiatives Task Force, and executive editor of SPE Reservoir Evaluation & Engineering, and was chairman of the San Joaquin Valley Section. Fattahi holds PhD degrees in aerospace engineering and mechanical engineering from Iowa State University.
How did you get involved with SPE?
I joined the oil industry in 1977, working in Iran for Osco/Shell Company. There was an interruption in my SPE membership because of all the events in Iran at the time, but when I came back to the US in 1985 to work for Shell in New Orleans, I became a member again. At the time, I had a passion to work on behalf of SPE but I did not really know how to, and I suspect that there are a lot of people today who have that problem—they want to get involved but they do not know the avenues to take and where to start.
It was not until I began working in Bakersfield, California, in the early 1990s that I really got involved with SPE. One day I received a call from a friend at Chevron who was on the board of the SPE local section and he asked me if I could help him with the continuing education program because he was going to move the next year. And that turned out to be the opportunity that I was looking for. I got involved in that program and, after he left, I was able to become the section's Continuing Education director and significantly increase the size of the continuing education program.
Horizontal-Well Fracturing: Why Is it So Different?
Authors: Daneshy Ali 
Published: February 2015

Technology Update
Advances in drilling and fracturing horizontal wells have been two of the main contributors to economic production from very-low-permeability oil and gas reservoirs. In spite of much attention to the subject, several critical questions regarding horizontal-well fracturing remain unanswered. Among these are higher fracturing pressures, large pressure fluctuations, and more frequent screenouts, which has prompted use of much finer proppant at very low concentrations. This article answers some of these questions.

Fracture Initiation From Horizontal Wells
The state of stress in a borehole gives it a natural tendency for longitudinal (axial) fracture initiation (Fig. 1a). This is a geometrical effect and independent of the in-situ stress orientations (Daneshy 1973). It can occur even when the least in-situ principal stress is parallel with borehole axis. Since the fracture is not perpendicular to the least in-situ principal stress, it takes higher pressure to extend it. As the axial fracture grows, it will eventually reorient itself to become perpendicular to the least in-situ principal stress and the fluid pressure gradually decreases with it. The location of fracture reorientation depends on location and orientation of planes of weakness in the formation. This leaves open the possibility that the fracture may reorient itself more than once, and depending on the orientation and size of the plane of weakness, may temporarily grow in directions other than perpendicular to the least in-situ principal stress.
Initiation of a transverse fracture (perpendicular to borehole axis) requires axial forces and stresses (parallel with borehole axis), which is shown in Fig. 1b. In open holes, such stresses can be induced inside open natural fractures, at the packer seats, or at the bottom of the well (if exposed to fluid), each with its own characteristics. This is shown in Fig. 2.
Natural fractures are randomly located and distributed along the well. Initiation from natural fractures results in random location, orientation, and spacing between fractures. One way for partial location control is to reduce the spacing between the packers, thus reducing the length of the pressurized interval.