bluuebunny/crossref_metadata_2025_split huggingface dataset:
State of the Art of Ultradeepwater Production Technologies
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 17615, "State of the Art of Ultra Deepwater Production Technologies," by J.M. Bell, SPE, Chevron; Y.D. Chin, SPE, Aker Kv ærner; and S. Hanrahan, SPE, Chevron, prepared for the 2005 Offshore Technology Conference, Houston, 2-5 May.
The full-length paper summarizes some results of several recent joint industry projects (JIPs) on ultradeepwater field-development technologies. A review of emerging and existing technologies for deepwater development is presented, which would be of particular interest to technology-development personnel and asset-team personnel who are in the appraisal or concept-selection stages of a project.

Introduction
As offshore production moves from deep water (3,000 to 6,000 ft) to ultradeep water (6,000 to 10,000 ft) and moves farther away from infrastructures, many existing technologies reach their limits or must be improved. Several successful JIPs have demonstrated that in the high-expense and -risk environment of ultradeep water, structured collaboration aligned with business drivers is a successful formula for delivering the technologies required to meet the ultradeepwater challenge. The demand for critical technology and engineering systems to enable production from ultradeep water has triggered breakthroughs in many conventional technologies. The full-length paper focuses on sub-sea, flow-assurance, floating-production-system, and riser technology.
Guest Editorial: Sometimes Bigger Is Better: Big Oil as Radical Innovators in E&P
Authors: Perrons Robert K. 
Published: February 2015

The 20th century economist Joseph Schumpeter famously aspired to be the greatest economist in the world, the greatest horseman in Austria, and the greatest lover in Vienna. He would therefore be quite pleased to discover that the first and most public of these objectives was at least partially achieved: One of his more famous economic predictions is apparently true. In the latter part of his career, Schumpeter postulated that large firms have many advantages over smaller ones in the development of radical new technologies. Whereas small and medium-sized enterprises frequently have to pay an undue amount of attention to their short-term balance sheets, large companies with deep pockets do not have to be nearly as sensitive to immediate profit constraints. Schumpeter accordingly reasoned that larger firms have both the resources and the time to pursue new ideas, and they are better positioned to explore the implications for their business of technological discontinuities before deciding whether to bring these technologies into the folds of the company's core activities and operations.
This is not to say that smaller firms will not have an important role to play in the development of new technologies within the E&P industry. Product and process life cycles are steadily growing shorter, and it is becoming increasingly difficult for any one company to support an aggressive R&D agenda single-handedly. Robert Z. Gussin, former Vice President for Science and Technology at Johnson & Johnson, once drove this point home by musing that technology in his industry "has become so sophisticated, broad, and expensive that even the largest companies cannot afford to do it all themselves." Responding to these same forces in the E&P industry, many large integrated majors have turned to their supply networks as a source of innovation.

Hit and Miss
To be sure, there is evidence from other industries that it is quite healthy for companies to rely to some degree on collaborative suppliers for new ideas. History has shown on many occasions that even the most focused R&D programs fail to guarantee results consistently. Many of the significant and commercially celebrated innovations that have emerged over the years have not been the result of tightly managed research agendas, but instead were brought about by a convoluted process of serendipity and unique circumstances. The hit-and-miss nature of R&D is such that managing science has been compared to herding cats: It is usually not done well, but one is surprised to find it done at all. Realizing that it is almost impossible to forecast where their next "new big thing" will come from, many companies across a wide variety of sectors are starting to broaden the radius of ideas that they might tap into by turning to their supplier base.
Subsea Smart Multilateral Wells Increase Reserves at Gullfaks South Statfjord
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 95721, "Subsea Smart Multilateral Wells Increase Reserves at Gullfaks South Statfjord," by V. Haugen, SPE, A.-K. Fagerbakke, SPE, B. Samsonsen, and P.K. Krogh, SPE, Statoil ASA, prepared for the 2006 SPE/DOE Symposium on Improved Oil Recovery, Tulsa, 22-26 April.
Production from the Statfjord formation in Gullfaks South (GS) field was limited by low connectivity, reservoir heterogeneity, and gas breakthrough. Surface-operated downhole inflow control and multilateral wells were identified as solutions to these limitations. Implementing a downhole-instrumentation and -control system (DIACS) and multilateral technology (MLT) in three horizontal subsea wells led to a two-fold increase in the reserves estimate to 5.4×106 m3 oil in the reservoir management plan for 2005.

Introduction
The GS field, operated by Statoil ASA, is in the Norwegian sector of the North Sea, approximately 150 km northwest of Bergen. The field is a subsea satellite tied back to the Gullfaks A and C plat-forms and consists of two independently developed reservoir units, the Brent and Statfjord formations. Production from the Statfjord formation, which began in 1999, is routed to Gullfaks A.
Fig. 1 shows the structurally complex Statfjord formation with many fault segments and indications of locally varying fluid contacts. The formation is approximately 300 m thick. Production experience, however, has shown less connectivity than expected. The initial reservoir pressure at 3300 m true vertical depth was 476 bar, and the reservoir temperature was 128°C.
In 1995, oil recovery from the GS Statfjord field was estimated to be approximately 40%. In 2001, after drilling the first three wells, further development of the field was postponed because of poor production performance, and the expected recovery factor was reduced considerably. In 2003, a project was established to improve the reservoir knowledge, identify cost-effective well solutions, and implement available technology suitable for further development of the reservoir. The project, with considerable support from the field partners, identified the need for more drainage points and robust solutions, particularly the use of MLT to account for geological complexity and reservoir uncertainty.

Multilateral and Smart Wells
Increasing exposure to the reservoir by increasing the number of drainage points is essential to maximize oil production and enable access to reserves that otherwise might be left behind. This solution minimizes the localized drawdown to help maintain an even pressure depletion in the reservoir.
Guest Editorial: Forces That Will Shape Intelligent-Wells Development
Authors: Mathieson Derek 
Published: February 2015

This year, the oil industry celebrates the 10th anniversary of intelligent-well completions, a revolutionary technology that has grown from a vision in the early 1990s to an industry-changing reality today. As the technology moves into its second decade, it is an appropriate time to reflect on the factors that have shaped the evolution of today's product lines and to consider the emerging market themes that will drive the next generation.
The origin of intelligent wells was prompted by a number of factors in the late 1980s:The first generation of subsea wells was moving into production decline and presenting many challenges in the execution of strategies to restore rates.Deepwater subsea wells, in which intervention would be prohibitively expensive, were being planned.Drilling-technology advances were leading to the development of complex wells, including horizontals, multilaterals, and extended-reach.
In effect, well-construction capability had outpaced the tools and workflow of production management, presenting a set of technical hurdles for well and production engineers to overcome. The challenge was to remotely monitor and control different sections or zones within a wellbore without the need for costly intervention. This need eventually would become the definition of "intelligent wells" and culminated in the installation of a surface-controlled reservoir-analysis-management system in 1997.

Market Hurdles
The first generation of intelligent-completion technologies consisted of a range of integrated electrical or electrohydraulic systems that included both sensing and control capabilities. These initial systems were complex and costly, and they were subject to a number of early field failures. In addition, all but a few users were unconvinced of the actual value proposition and were uncertain about how to express that value in a clear business case for each well. Survival of the technology was challenged initially by market-imposed hurdles of reliability and economic viability. Both of these themes remained dominant over the first 5 years of evolution and led to two clear decisions about development of the second generation of products: focus on all-hydraulic solutions to mitigate risk and focus on simple open/close-type control in subsea wells to avoid intervention and justify the economic case.
Thus, from around 1998 to 2003, most intelligent-well installations were simple open/close hydraulic valves, predominantly applied in subsea wells in the North Sea and the Gulf of Mexico. This period produced a rich set of reference material on economic modeling of active reservoir-management technologies and, more importantly, led to a cultural change for many of the major oil service companies, as they began to embed reliability-engineering practices into the development of oil tools.
Technology Update: Top-Drive Casing-Running Tool Solves Tough ERD Problems
Authors: JPT staff _ 
Published: February 2015

Over the past 15 to 20 years, top-drive technology has brought substantial improvements in efficiency and safety to drilling operations. However, casing-running methods have evolved more slowly and have not taken advantage of all the potential offered by top-drive drilling. Weatherford International has designed its new Overdrive system for running casing and drilling with casing to make full use of the weight and power of top drives (Fig. 1). The system won a Spotlight on New Technology Award at the 2007 Offshore Technology Conference.
This top-drive casing-running system was used recently by Shell to land casing on bottom at more than 18,200 ft depth on a troublesome North Sea extended-reach-drilling (ERD) well with hole restrictions caused by inability to clean the hole completely.

Torque-Drive Tool
The centerpiece of the technology is the torque-drive tool that combines several conventional casing-running tools into one—power tongs, main hoisting elevators, bails and single-joint elevators, a fill-up/circulation tool, and a weight compensator. All system operations are remote so that no personnel are required in the derrick or on the rig floor, resulting in a significantly lower safety risk (Fig. 2). The removal of equipment and scaffolding from the rig floor also creates a safer work environment.
The torque-drive tool is connected below the rig's top drive and can be run with any topdrive system. To run casing, the tool's integral bails and single-joint elevators are used to retrieve each joint or stand of casing, lift it into the derrick, and lower it into position for makeup. The torque-drive tool is then hydraulically clamped onto the casing, and the connection is made up using the rotational power of the top drive to transfer the torque through the torque-drive tool and casing connections.
A key component used in conjunction with the torque-drive tool is an integral electronic-load cell called the torque sub, mounted at the top of the torque-drive tool and used to measure the makeup torque of the casing connections. The sub is independent of the top drive and measures true torque, as opposed to conventional techniques that calibrate torque from the voltage that supplies rotational power to the top drive. This new level of accuracy is especially important when making up premium connections, which require torque-turn monitoring and a very low margin of torque-measurement error.
Once the connection is made up, the driller can instantly perform a number of operations as needed, including fill-up of the casing string while lowering, and simultaneous circulation, rotation, and reciprocation of the entire casing string. This combination enables the driller to overcome virtually any unexpected hole problems, such as ledges, lost-circulation zones, shallow-water flows, and swelling formations. This greatly enhances the ability to run the casing string to bottom in a predrilled well.
Overview: Intelligent Fields Technology (August 2007)
Authors: Gomersall Sam 
Published: February 2015

Intelligent Fields Implementation: Why Is It Taking So Long?
We have been talking about intelligent fields or digital oilfield matters for some time, and while a significant number of papers have been written on the subject, mainstream application of the technology is patchy. Given the benefits from making better use of our data, why is it that the broad application of the digital oil field has not yet happened? Having been involved over the last 5 years or so, I see five inhibitors.Not enough focus on people and process—It is too easy to see the digital oil field as a new software product. In reality, how data is used in various processes, how workflows could change, and how people interact with data are fundamental to achieving the benefits of the digital oil field.Seeing the digital oil field as a single product—In reality, digital oil field is all about integration: integration of existing software, integration of data sources, and integration of data. This integration requires clarity of the architecture, the data flows, and the output requirements.Aiming for a fully linked integrated model before addressing fundamentals—It is key to start with appropriate instrumentation, data collection, surface control and data acquisition systems, and data conditioning to achieve early benefits from effective visualization and simple analysis. More-complex linking of integrated asset models should wait for "Phase 2."Lack of scalability—Often, assets develop solutions to address the immediate local business need without giving due consideration to being able to scale the solution to other assets. I fully support business-unit-led developments, but a corporate guide is required to ensure that they fit with the overall strategy.Difficulty in sustaining momentum—Enthusiasm, commitment, and resources at build stage can fall away if a key individual moves. Even a fully implemented system can be difficult to sustain if it is not applied consistently across assets.
Being aware of these traps and working to address them provides significant opportunity for wider mainstream application of digital oilfield technology over the next few years. Like you, I look forward to it.
Intelligent Fields Technology additional reading available at the SPE eLibrary: www.spe.org
SPE 104161 "Advanced Production Monitoring" by Martijn Hooimeijer, Shell Global Solutions, et al.
SPE 104227 "Smart-Well Completion Utilizes Natural Reservoir Energy To Produce High-Water-Cut and Low-Productivity-Index Well in Abqaiq Field" by Nashi M. Al-Otaibi, SPE, Saudi Aramco, et al.
SPE 105374 "A Novel Approach of Detecting Water-Influx Time in Multizone and Multilateral Completions Using Real-Time Downhole Pressure Data," by G.H. Aggrey, Heriot-Watt University, et al.
SPE 105618 "Smart Wells: Experiences and Best Practices at Haradh Increment-III, Ghawar Field," by Ibrahim H. Al-Arnaout, Saudi Aramco, et al.
Ormen Lange Subsea Production System
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 18965, "Ormen Lange Subsea Production System," by Thomas Bernt, Hydro, and Endre Smedsrud, FMC Technologies, prepared for the 2007 Offshore Technology Conference, Houston, 30 April-3 May.
The Ormen Lange field, in the Norwegian Sea, approximately 100 km off Norway, is within the prehistoric Storegga slide area with water depths reaching 850 m in the main production area. The gas will be produced from up to 24 subsea wells. The well fluid will be transported to the Nyhamna plant through two 30-in. multiphase lines. After processing, the dry export gas will be transported from the onshore plant through a new 42-in. pipeline by way of the Sleipner riser platform and further through a new 44-in. pipeline to the gas-receiving terminal in Easington, England.

Introduction
Fig. 1 shows the development concept selected for Ormen Lange, which comprises a subsea tieback to an onshore processing plant at Nyhamna. Conceptual engineering of the subsea production system was initiated in 2002. The main contracts for subsea-equipment supply, umbilical fabrication, and template installation were awarded between the autumn of 2003 and the summer of 2004. The main part of fabrication and testing took place during 2004–05, with the subsea templates installed offshore in late summer 2005. Umbilical A and the remaining subsea equipment were installed during the summer of 2006, and the first subsea tree was installed on Template A in December 2006. Completion of the first subsea well on Template A was scheduled for spring 2007, and subsea production startup was scheduled for autumn of 2007.

Subsea-System Configuration
With the large geographical extent of the Ormen Lange reservoir and the risk of reservoir segmentation, the subsea-system design has a high degree of flexibility, with four planned template locations. Therefore, a phased-development scheme was chosen. The phasing and location of the subsea wells will be timed to maintain plateau production as the field depletes.
Initial Development. The initial sub-sea development consists of two eight-slot production templates (Templates A and B), approximately 4 km apart in the main production area. Each tem-plate is tied back into the two 30-in. multiphase pipelines to shore. As Fig. 2 shows, these lines are interconnected through a pipeline-end-termination (PLET) system.
Two main control umbilicals link the onshore plant to the subsea production system; one is connected to Template A and the other to Template B. A cross-over-control umbilical interconnects the two production templates, providing redundant hydraulic supply to all the subsea wells.
To prevent hydrate formation, all wells are injected continuously with monoethylene glycol (MEG) through two 6-in. pipelines from the onshore plant. One line is connected to Template A and the other to Template B. A 6-in. crossover-MEG line interconnects the two production templates for added flexibility.
Overview: Unconventional Recovery (August 2007)
Authors: Norris Stephen O. 
Published: February 2015

In the year 1419, Filippo Brunelleschi entered a competition to solve the most daunting architectural and engineering challenge of his time: designing and building the Dome of the Cathedral of Florence. The problem was that when the building was designed in the previous century, no one had any idea about how such a dome would be built (imagine that). To further complicate matters, buttresses were forbidden by the city fathers, internal scaffolding was undesirable, and the use of concrete had long been forgotten, which meant the dome had to be built out of bricks. Worse, his rival, Lorenzo Ghiberti, who was appointed coadjutator for the project, publicly mocked his plans and called them unfeasible.* (Think about that the next time you have a bad day at the office!) Fortunately for Florence and for Renaissance architecture, Brunelleschi endured the hardships and technical challenges to design and create one of the world's most famous and admired structures.
Today, we are faced with a daunting challenge: How can we supply the world with the energy our economies demand and, at the same time, reduce the emission of greenhouse gases, burn cleaner fuels, and improve air quality in our cities?
In this section, we will look at new technologies that hold at least a promise for meeting this challenge: simultaneous coalbed-methane production and CO2 sequestration, gas production from hydrates, and the use of hydrogen as a fuel for automobiles.
Certainly, we do not have all of the answers yet, and we will need to rely on innovators, like Brunellschi in the 15th century, to provide ingenious and unprecedented solutions. But with dogged determination, a little patience (it took 16 years to build the dome), and plenty of public education and support, I think we can make a difference that will improve the lives of many generations to come. Imagine that.
Unconventional Recovery additional reading available at the SPE eLibrary: www.spe.org
SPE 100674 "Data Analysis of Barnett Shale Completions" by B. Grieser, Halliburton, et al.
SPE 101109 "Changes in Completion Strategy Unlocks Massive Jurassic Coalbed Methane Resource Base in the Surat Basin, Australia" by R.L. Johnson Jr., SPE, Queensland Gas Company, et al.
Available at the OTC Library: www.otcnet.org
OTC 19090 "Electrical Collection and Transmission Systems for Offshore Wind Power," by Jim Green, National Renewable Energy Laboratory, et al.
* Wikipedia: http://en.wikipedia.org/wiki/Filippo_Brunelleschi and http://en.wikipedia.org/wiki/Florence_Cathedral. Accessed 18 June 2007.