bluuebunny/crossref_metadata_2025_split huggingface dataset:
R&D on Campus: Developing Upstream Technology
Authors: Braswell Gentry 
Published: February 2015

Editor’s note: JPT surveyed major universities around the world regarding their key upstream research and development projects and activities. This is the second installment of the two-part series.
Harold Vance Department of Petroleum Engineering, Texas A&M University, US
The Crisman Institute for Petroleum Research at Texas A&M University houses the Halliburton Center for Unconventional Resources, the Chevron Center for Well Construction and Production, the Schlumberger Center for Reservoir Description and Dynamics, and the Center for Energy, Environment, and Transportation Innovation. The focus of each center is to develop technology and processes to reduce the finding and development costs in petroleum reservoirs. The institute facilitates funding for graduate programs and research that includes work toward better mathematical models, better rheological reservoir control chemistry, and better predrilling geological interpretation and well modeling.
Texas A&M’s Global Petroleum Research Institute (GPRI) is the managing partner of a cooperative effort among 12 major oil producing companies conducting critical research in developing technologies to address the increasing demand for cost-effective production and enhanced recovery. The GPRI is primarily focused on unconventional resources, said David Burnett, research coordinator. There has been a “sea change” in focus since the US gas shale plays have emerged and offered opportunity to make gas a fuel supply for the power grid, he said. It is important to teach students, industry sponsors, and the public about appropriate water use and handling in drilling, as one’s license to operate is ultimately determined by environmental performance, Burnett said. If an operator is inattentive or environmentally negligent, it ends up out of business. “And one of the biggest parts of that is water,” Burnett said.
It takes lots of water to drill, and for 50 or 60 years the industry has reinjected produced water into the reservoirs. But shales are not reservoirs, so there is no way to appropriately reinject them, Burnett explained. Besides water treatment in gas shales, GPRI is currently collaborating with major operators on developing an environmentally friendly seismic signaling device and is also researching ways to keep deep sea pipelines from getting clogged, which is a challenge because low deep sea temperatures cause produced hydrocarbons to congeal.
Integration of 3D Seismics and Reservoir Simulation for Remaining-Oil Exploitation in a Heavy-Oil Field: SAGD Case Study
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 134092, ’Integration of 3D Seismics and Reservoir Simulation for Remaining-Oil Exploitation in a Heavy- Oil Field: A Case Study,’ by Yun Ling, BGP CNPC; Xuri Huang, SPE, SunRise PetroSolutions Tech; and Xiangyu Guo and Yintao Cai, BGP CNPC, prepared for the 2010 SPE Annual Technical Conference and Exhibition, Florence, Italy, 19-22 September. The paper has not been peer reviewed.
Integrated research on steam-assisted gravity-drainage (SAGD) production was carried out for an oil field in north-eastern China by use of full-azimuth 3D seismics (cell size 6.25×6.25 m with a coverage area of 14 km2) and reservoir simulation on a well group [40 vertical wells and five horizontal wells in an area of 600×375 m (Fig. 1)]. The research indicated that the configuration of steam chambers caused by steam injection could be delineated from the high-resolution 3D-seismics results, and that this is more accurate than the reservoir-simulation model alone in the local-variation description of the chambers.
Introduction
It has been observed in laboratories that a large seismic-velocity change can occur in rocks containing heavy oil when the oil is replaced by steam. The Duri heavy-oil field in Indonesia uses steam injection, and time-lapse seismics is used to monitor production. However, the effectiveness and reliability of the method depend on the quality and repeatability of the surveys. The technique of combining 3D-seismic exploration for the remaining oil with historical production data (called 3.5D seismics) avoids the nonrepeatability problem commonly associated with time-lapse seismic. This technique was applied to the Ng reservoir in northeastern China.
Geological and Seismic Background
The main producing reservoir, Ng, is on a monoclinal structure covering 1.95 km2. Its maximum thickness is 145 m and is found at a depth between 540 and 800 m. The reservoir porosity is 36%, permeability is 5.5 darcies, and the reservoir has edge, top, and bottom water. Production started in 1997, and 10 to 12 cycles of steam stimulation have been implemented in a well interval of 70 m. Enhanced oil recovery (EOR) reached 20 to 25%. Starting in 2005, five SAGD well pairs were used, and they are still in production. The SAGD process raised the EOR by 5 to 10%. A high-density 3D-seismic survey (with a wide azimuth and an aspect ratio of 0.874) was acquired in February 2009. The processing procedure that was used enhances the vertical resolution and preserves reservoir information.
Best Practices and Innovations for Improved ESP Performance
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 136407, ’Best Practices & Innovations for Improved ESP Performance; Mature Field Case History; TNK-BP Company, Russian Federation,’ by D.C. Borling, SPE, BP, and S.V. Sviderskiy, SPE, and, S.F. Gorlanov, SPE, TNK-BP, originally prepared for the 2010 SPE Russian Oil & Gas Technical Conference and Exhibition, Moscow, 26-28 October. The paper has not been peer reviewed.
Leadership, teamwork, and technical ingenuity were critical strategy elements that resulted in an 82% run-life improvement for electrical-submersible-pump (ESP) systems in the TNK-BP company. During the past 4 years, the 12-month rolling mean time between failure (MTBF) steadily improved from 295 days during January 2006 to the current 541 days in July 2010. This 246-day improvement was achieved across more than 14,250 ESPs and achieved USD 307 million value to date.
Introduction
TNK-BP is a privately owned oil and gas joint venture. The company was formed in 2003 and for the past 7 years its upstream producing operations were located primarily in West Siberia (Khanty-Mansiysk and Yamalo-Nenets Autonomous Districts, Tyumen Region), East Siberia (Irkutsk Region), and Volga-Urals (Orenburg Region).
As of July 2010, the company operated more than 200 hydrocarbon-bearing fields with approximately 15,700 active producing oil wells. More than 98% of these wells used artificial lift.
In TNK-BP, ESP systems refer to both surface and downhole equipment components. Surface components include transformer, switchboard (and/or variable-speed motor controller), and a relatively short surface power cable. Downhole components include pump intake (and/or gas separator), seal element, motor, and a long downhole cable (used to transfer power from the surface to the motor).
Operating Conditions
Each of the company’s 14 regional business locations has unique operating conditions. By mid-2010, more than 50 different types of ESP equipment were deployed across the company to lift a wide range of produced-fluid rates and gas and solid content.
Approximately 92% of all deployed ESP equipment was manufactured within the Russian Federation. The remaining 8% was imported for use in complicated well conditions and harsh downhole operating environments.
TNK-BP deployed ESP equipment in almost every type of downhole condition imaginable. Harshest conditions included a mixture of high temperature, abrasive solids, scaling, asphaltene, paraffin, high free-gas content, and corrosive fluids.
Teamwork
Without good teamwork on a massive scale across five business segments and 14 regional businesses, the TNK-BP ESP-MTBF-improvement initiative would not have achieved the intended results.
A best practice was the method used to align ESP MTBF key performance indicators and work plans at the start of each year. While this alignment was a big undertaking, it proved itself to be worth the effort each year.
Use of a Vertical Wind Turbine in an Offshore Floating Wind Farm
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 21705, ’Use of a Vertical Wind Turbine in an Offshore Floating Wind Farm,’ by Marc Cahay and Eric Luquiau, Technip, and Charles Smadja and Frederic Silvert, Nenuphar, originally prepared for the 2011 Offshore Technology Conference, Houston, 2-5 May. The paper has not been peer reviewed.
With 2.0 GW already installed and more than 50.0 GW planned in Europe by 2020, as reported by the European Wind-Energy Association, the installation of bottom-mounted offshore wind turbines in very shallow water (less than 40 m) is now well established. The foundation and the offshore installation costs represent approximately 50% of the total development cost of an offshore wind farm, and this proportion increases with the water depth. Hence, floating wind turbines are the solution for deep offshore.
Vertiwind Project
Coming from a strong and complementary partnership of utilities, industrials, and academics, the Vertiwind project plans to build, install, and operate, in real offshore conditions, a full-scale floating vertical-axis wind turbine (VAWT) of 2 MW. This is a real step change in the technology compared with most offshore wind turbines with horizontal axes.
The floater concept retained is of a semisubmersible design and is called “multifloater.” It skillfully combines an out-of-the-wave excitation response, a shallow draft to facilitate fabrication, and a very simple installation procedure requiring only one or two tugs. The VAWT is located in the center of the floater, ensuring that the center of gravity, the buoyancy, and the convergence point of the mooring lines are all on the same axis. This geometrical property highly reduces the sway and yaw response of the floater subject to noncolinearity or heading variation of wave and wind. Because of the architecture and underlying principles of this Darrieus turbine, the power production is not affected by the inclination of the turbine axis relative to the wind direction as a result of the floater motions.
The turbine design is carried out in parallel with the floater. It integrates, at an early stage, all requirements of the offshore environment in terms of loads, accessibility, and ease of maintenance. The complete unit will be anchored to the seabed and linked to the network by a compliant subsea cable.
Techbits: Workshop Focuses on Critical Issues of Social Responsibility
Authors: JPT staff _ 
Published: February 2015

Techbits
Social responsibility (SR) is the newest element within the health, safety, security, environment, and social responsibility (HSSE SR) field of the oil and gas industry. SR is a nontechnical risk, and its professionalization requires multidisciplinary teams with specialists in capacity building, resolution of conflicts, and human rights. Appropriate SR management aims to increase cost effectiveness, minimize legal and financial liabilities, build reputational capital, drive innovation, and capture business opportunities.
A connection between HSSE and SR is essential, but few organizations have clearly defined what constitutes excellence in SR performance or programs, especially in project development. As one of the many “business risks” that the industry faces, it is likely that social pressures will force additional action and attention on SR. Organizations must understand and communicate SR risks to internal stakeholders to effectively address them during project development.
SPE recently held its first Social Responsibility Workshop in Paris. The workshop explored the key SR challenges facing the oil and gas industry, sought to establish a common understanding about terms and practices, and provided an opportunity for participants to learn from the operational experiences of major industry players.
The workshop was divided into seven sessions.
Social issues compliance and the value of social risk management
Stakeholder engagement in the life cycle of an exploration and production (E&P) project
Opportunity and risk analysis
Operating in conflict-affected or high-risk areas
Working together: the range of players and their roles
Challenges during the project development’s life cycle
Success stories: overcoming challenges in implementing SR in operations
Best practices for corporate management of social issues and regulatory compliance have evolved greatly over the past 10 years. The first session explored current thinking on best practices in the industry. In a changing world with no more “easy oil,” there is a shift in the size of projects, from a typical USD 3 billion to 5 billion price tag in the early 2000s to an impressive USD 35 billion this year for a project in Australia. There is also a change in project time frame, which has nearly doubled in the past decade. The average project delay is 1 year, and 73% of delays are caused by nontechnical risks. With this growth and change come new demands from leadership that requires new, proactive positions on such risks. Part of the challenge is to recognize that new sources of risk exist and that new approaches to risk management are required.
Apps and the Digital Oil Field
Authors: Beckwith Robin 
Published: February 2015

App technology
The oil and gas industry tends to be resistant to marketing fads. If a software phenomenon such as the app cannot help get oil and gas out of the Earth safer, faster, and more economically, then the industry will not use it. This may be why, of the hundreds of thousands of apps now publicly available, only a few dozen are devoted to the industry.
Apps Developed for the Oil and Gas Industry
None of the online app stores has a separate category for the petroleum industry. Oil and gas apps are primarily housed under app stores’ business, education, productivity, or reference headings. While an app must meet certain software standards to be included in an app store, the actual content receives no vetting. So, beyond the name and reputation of the company or person providing the app, no assurance is provided on the accuracy of the app’s information, mathematical formulas, or simulation parameters.
Oil and gas industry apps comprise the following five categories:
Those devoted to marketing materials—These marketing collateral materials take the place of printed catalogs, annual reports, brochures, and data sheets. While companies have made such materials available on their websites ever since the Web began rising in prominence in the early 1990s, the primary advantage of accessing them via a smartphone or tablet lies in the greater portability of the devices themselves, as well as the ability for updated material to be added at any time.
For example, Aker Solutions recently implemented a smartphone app for its wireline tractor catalog. On a tablet, this is downloaded as a portable document format (PDF) file that is accessible through a book library app.
In another example, Tenaris has created its own TenarisLibrary, featuring a complete and integrated package of its available marketing literature and videos. These appear in a variety of languages, and access can be tailored to individual interests. Calling it a “dynamic library,” Tenaris writes, “Each user is invited to create their own customized library to navigate the material once disconnected from the Internet.”
Those that supply computations—Designing a drilling program and constructing, drilling, and completing a well demand input of a huge number of variables that can be manipulated using mathematical formulas and computations. Each variable rests upon a solid foundation of physical reality, including measured depth, pipe inner and outer diameter, downhole pressure and temperature, azimuth, mud weight, rate of penetration, and weight on bit. Some computationally based apps—including Halliburton’s eRedBook and eChartBook and Schlumberger’s Smith Bits Quick Calc Hydraulics—are of use in the field. Others—such as Wellcontrol.com.br’s Well Control, Leak-Off Test, and Drilling simulators—are useful as educational tools.
Deepwater Spill Control Devices Go Global
Authors: Rassenfoss Stephen 
Published: February 2015

The first thing a visitor sees at Trendsetter Engineering is a massive device standing ready if the worst happens on a well in the Gulf of Mexico. This amalgam of connectors, pipes, valves, and blowout preventers (BOPs) is a capping stack—a name that entered the language in 2010 when the first one was quickly assembled to shut off the flow of oil from the Macondo field.
The Helix Well Containment Group (HWCG), which has 25 member companies, stores this early example of what has become a global trend. Industry organizations and operators now have more than 15 capping stacks in service and on order.
Many of them have been built, or will be, at Trendsetter. On a day in early April, the engineering consulting and equipment maker was building a capping stack for Shell, which will be part of its Arctic drilling program.
And they were planning to build another designed by Shell to fit into the narrow space beneath a tension-leg platform. When complete, that one will become the property of the Marine Well Containment Corp. (MWCC), serving 10 large operators in the Gulf of Mexico. By year’s end, MWCC will have three capping stacks and a growing inventory of related equipment, including two vessels to capture, process, and offload crude to tankers and flare natural gas.
Another four capping stacks to be built by Trendsetter will be deployed to offshore oil basins around the globe by the Subsea Well Response Project (SWRP), a nine-member Norway-based industry group.
BP recently added another capping stack in the Houston area that also has a global mission. The device, weighing more than 100 tons, can be broken down into two pieces and flown anywhere that BP is working offshore, said Geir Karlsen, BP Containment Response Team leader.
A variety of factors are pushing a trend that started in the Gulf of Mexico after the Macondo disaster led regulators to require that operators seeking drilling permits demonstrate they can control a deep sea blowout. Two ventures, MWCC and HWCG, were created to cooperatively provide those services in the Gulf of Mexico.
When Shell sought permits to drill offshore in Alaska, it faced a similar requirement and needed a capping stack there.
In the North Sea, operators formed the Oil Spill Prevention and Response Advisory Group (OSPRAG) with a stack built by Cameron designed for conditions there.
International oil companies, such as Shell and BP, have internal standards for offshore operations requiring capping stacks be available around the world, which many countries are coming to expect. They responded with caps of their own and by being part of SWRP.
Fayetteville-Shale Production: Seismic-to- Simulation Reservoir Characterization
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 147226, ’Understanding and Predicting Fayetteville-Shale Gas Production Through Integrated Seismic-to-Simulation Reservoir-Characterization Workflow,’ by Hariharan Ramakrishnan, SPE, Eva Peza, Shekhar Sinha, SPE, and Miriam Woods, Schlumberger, and Christopher Ikeocha, Flemming Mengel, Yves Simon, Paul Pearce, Jeff Kiester, Steven McKetta, SPE, and John Jeffers, SPE, Southwestern Energy, prepared for the 2011 SPE Annual Technical Conference and Exhibition, Denver, 30 October-2 November. The paper has not been peer reviewed.
A comprehensive workflow was developed that incorporates geologic, seismic, and production data in an effort to understand and predict the performance of gas wells in the Fayetteville shale play. A reservoir model was developed by integrating all available well, log, petrophysical, sonic, image, core, stimulation, production, microseismic, and processed surface-seismic data. This static reservoir model was used to history match the short- and long-term production performance and its variations across the exploration area. The reservoir characterization and the dual-porosity simulation model were used to predict production performance of future wells in the Fayetteville shale formation.
Introduction
Significant technological advances have been made toward identifying shale-gas resources and developing those resources economically. Acquiring (and use of the correct combination) of information and measurements to understand production capabilities early in the life of a large play remains a critical challenge. An integrated seismic-to-simulation workflow was developed to understand and predict the production performance of Fayetteville shale-gas wells.
The Fayetteville shale-gas play extends across northern Arkansas, USA, from the state’s western edge through-out north-central Arkansas. Ranging in thickness from 50 to 550 ft and varying in depth from 1,500 to 6,500 ft, this Mississippian shale is the geologic equivalent of the Barnett shale in north Texas and the Caney shale in Oklahoma. Currently, this operator controls approximately 916,000 acres, which produced 350 Bcf of gas in 2010. Between the start of the project in 2004 and 31 December 2010, the company had spudded 2,445 wells.
Geological Setting
The structures in this area are the result of Precambrian-to-Cambrian rifting that generated the Reelfoot rift, also called the Mississippi Valley graben, and subsequent compressional tectonics of the Ouachita orogeny. The rifting event generated large normal northeast-striking faults, whereas the tectonics related to the development of the Ouachita orogeny is characterized by generally north-directed thrusting as a result of continent-to-continent collision along the southern margin of North America. The current orientation of maximum horizontal stress is northeast/southwest. In the study area, the Fayetteville shale is 250 to 300 ft thick and at a depth of 2,500 to 3,000 ft.