bluuebunny/crossref_metadata_2025_split huggingface dataset:
Overview: Natural Gas Technology/Monetization (April 2005)
Authors: Vitucci John 
Published: February 2015

Developing the world’s natural-gas resources continues at the forefront of the industry as we continue to embrace clean-energy initiatives and gas discoveries continue to increase on a worldwide basis. Once considered a nuisance by the industry, natural gas has become the leading clean energy to lead us into the future. Our industry continues to develop innovative ideas and technologies for finding, producing, transporting, and distributing natural gas. The drilling, completions, reservoir-characterization, and production disciplines continue to generate new technology, improve existing technologies, and improve our understanding of subsurface information. Transport, processing, and distribution technologies [e.g., liquefied natural gas, gas to liquids (GTL), and gas to wire] continue to make natural gas a viable option to a greater number of markets. Unconventional gas sources, such as coalbed methane, continue to grow in importance as technology improves production and economics. New technologies for gas-hydrate production and stranded-gas use are in their conceptual phases.
As one looks across the natural-gas value chain from reservoir to end markets, there is a realization that technology is driving our ability to develop natural gas into a leading energy resource for the world. The broad diversity of technologies surrounding natural-gas production and use makes it difficult to capture in a few select articles. The feature papers included this month are only a sampling of our industry’s innovative technologies and our ability to apply these technologies for economical use of the world’s natural-gas resources. I encourage readers to review the list of additional technical papers to fully appreciate our collective ability to develop natural gas in meeting the world’s energy needs well into the future.
Additional Natural Gas Technology/Monetization Technical Papers
Available at the SPE eLibrary: www.spe.org
SPE 90530 - The Significance of Non-Darcy and Multiphase-Flow Effects in High-Rate Frac-Pack Gas Completions
SPE 92764 - The Planning and Drilling of Hot Ice No. 1—Gas-Hydrate Exploration Well in the Alaskan Arctic
SPE 90177 - Risk, Uncertainty, and Optimization for Offshore-Gas-Asset Planning in Litoral Tabasco
Software Tool Improves Fractured-Reservoir Characterization and Modeling
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 88785, "New Software Tool Improves Fractured-Reservoir Characterization and Modeling Through Maximized Use of Constraints and Data Integration," by K. Rawnsley, Shell Intl.; P. Swaby, SPE, SSL; S. Bettembourg, S. Dhahab, H. Hillgartner, and M. de Keijzer, Shell Intl.; P. Richard, and P. Schoepfer, PDO; and B. Stephenson and L. Wei, Shell Intl., prepared for the 2004 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 10-13 October.
To enhance oil recovery from several fractured-carbonate reservoirs in Oman, Shell’s carbonate-development team and Petroleum Development Oman (PDO) applied a workflow and a research-software package aimed at better characterizing the complex subsurface. The work-flow comprised several steps, each supported by a multidisciplinary research program and implemented in an integrated-software environment for application to field development and enhanced-oil-recovery projects. The software tool, which interacts with existing static- and dynamic-modeling packages, produces integrated reservoir models including fracture-specific information.

Introduction
The main objectives of these studies were to provide enhanced constraints on fracture modeling in the subsurface. The following are important aspects of fracture systems, which typically are poorly constrained by subsurface data alone.
- Accurate 2D and 3D characterization of structural objects, especially fracture corridors and the internal geometries of fault zones.
- Organization of multiscaled fracture systems within mechanically layered rocks (i.e., the vertical extents of fractures intersected by wells).
- Internal flow properties of the fractures.
Several reservoir studies were carried out in parallel, for example in the northern Oman region, operated by PDO, providing an excellent opportunity to link observations made at the surface with the complete reservoir data sets. The current research builds on the understanding of the regional structural framework and evolution of North Oman from previous studies. The objective was to show how a software tool developed in Shell facilitated bringing research and field studies together to pro-vide enhanced reservoir characterization. Fig. 1 shows a generic workflow.
3D Visualization: A Common Language for the Drilling and Subsurface Communities
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 90659, "3D Visualization: A Common Language for the Drilling and Subsurface Communities," by C. Telford and M. Burns, BP plc, and N. Whiteley, Landmark Graphics Corp. Ltd., prepared for the 2004 SPE Annual Technical Conference and Exhibition, Houston, 26-29 September.
3D visualization has enabled the Andrew field team in the North Sea to develop a common understanding of geologically related drilling hazards to achieve best-in-class drilling performance on Well 16/28-A16. Improvement continued in Well 16/28-A17 with further reduction in geologically related nonproductive time (NPT). The common language pro-vided by the 3D-visualization tools enabled the different disciplines onshore and offshore to communicate effectively, integrating the team.

Introduction
This paper describes how the reservoir model, pressure cube, and structural model were used with the 4D seismic to identify the geological targets in the reservoir. These models, together with historical drilling NPT data and mapping of the overburden, were used to determine the optimal wellbore trajectory. The ability of the multidisciplinary team to view the subsurface field data along-side the drilling NPT information provided a greater understanding of potential risks and challenges and ensured agreement by all in the project from planning through to production. Visual images developed during the planning process then were used to brief the drilling and subsurface contractor services in technical-limit, prespud, and refresher sessions before each drilling phase.
Techbits: Digital Energy Conference Tackles Range of Issues
Authors: JPT staff _ 
Published: February 2015

Oilfield applications of digital technology, including best practices, cutting-edge applications, and future technologies, were the themes of "Digital Energy 2006: Bytes and Barrels," a 2-day conference held in Houston in February. SPE and the SPE Gulf Coast Section worked together on the event, the sixth annual conference on applications of digital technology in the oil and gas industry. The event featured the perspectives of operators, service companies, and firms directly involved in information technology (IT) on such issues as data management, how demographics will influence IT, production-operations monitoring, collaboration, systems integration, and drilling and operations.
In the conference keynote address, Steven B. Hinchman, Senior Vice President of Worldwide Production for Marathon Oil Corp., addressed "New Work Processes Required for Success." Supply and demand factors will influence how companies operate in the future, he said. "The global energy outlook really defines this changing work model," Hinchman said. Those factors include rising energy demand, especially in places such as China; growing transportation demand; the rise of natural gas as a global commodity; and a heavier and more sour barrel of oil that is becoming more difficult to produce.
"The most critical question international oil and gas companies face today is access to resources," Hinchman said. By 2020, the industry will need to provide 125 million BOE in additional production capacity because of the rise in global demand and the decline rate of current producing fields, he said.

Changing Relationship
Another issue affecting how companies operate is the changing relationship between private international oil companies (IOCs) and national oil companies (NOCs), Hinchman said. NOCs control most of the world's reserves and are becoming increasingly active in the international arena. And today, NOCs have access to the industry's conventional technology, have more financial resources than they did in the past, and are becoming more active outside their borders. "IOCs will have to be able to differentiate themselves," he added.
Oil and gas is becoming increasingly harder to produce because of rising E&P complexity and access to resources. Much of the industry's focus in the future will be on producing unconventional oil and gas, new gas technologies such as liquefied natural gas and gas to liquids, Arctic seas drilling, and ultradeepwater drilling. "All this means is that technology will play an even more important role in the next 20 years than it has in the past 20," he said. The industry's well-noted demographic challenges also will add pressure to how companies operate.
Hinchman sees the need for a "new generation work model" that would involve:Integration of resource holders, suppliers, and vendors.Increased productivity.Disciplined processes and work flow.Leveraging of technology.Globalized work teams.Accelerated learning and knowledge transfer.
Technology Tomorrow: The Next Trillion: Anticipating and Enabling Game-Changing Recoveries
Authors: Saleri Nansen G. 
Published: February 2015

Editor's note: This is the second installment of a yearlong series designed to stimulate discussion in research and development. The Technology Tomorrow articles will be published every other month and vary in emphasis, covering topics as broad as R&D industry trends and as focused as improving reservoir recovery factors. This series is one of several actions being taken by the SPE R&D Advisory Committee to encourage R&D development and discussion. The target audience is the entire readership of JPT. We hope to create a forum that sparks discourse and ideas, including ideas that may not be in the current mainstream of thought. Comments on the articles are welcome. Please send any questions, comments, or ideas to vik.rao@halliburton.com.
By any measure of efficiency, globally reported expected ultimate recoveries (EURs) have been less than impressive. The often-quoted industry average of 35% recovery (for conventional crude oil) sets a useful benchmark for the future, and raises the question, "Can we double it for the next trillion?" As we look ahead to April 2007, the date of the first SPE R&D Conference, one might ponder several related questions: How high can the industry stretch EURs? What are the major impediments to achieving them? Do R&D programs have a role to play, or does the spontaneous technology boom in the industry coupled with free-market dynamics signal the end of organized R&D?
A quick look at global oil resources, their acknowledged uncertainties not withstanding, calls for some perspective on this issue (Fig. 1). In 2005, global consumption had depleted only one out of seven barrels of conventional oil initially in place (and a fraction of nonconventional), a point perhaps overlooked by peak-oil advocates (Deffeyes, 2005; Tertzakian, 2006). A 10% incremental recovery translates to about 1.4 trillion bbl of recoverable resources, roughly an additional 50-year supply of global crude consumption at current rates. The gains in gas reserves could be equally rewarding.
The point is not so much to argue for the veracity or the feasibility of these figures. Instead, the intent is to highlight vast possibilities in the context of twin questions: How can R&D shape the energy future, and how should the desired future outlook govern present-day R&D? Intent matters! The industry has no choice but to articulate its own anticipations for the future regarding trillions of barrels of recoverable resources. The recovery standards of the past century certainly cannot be the basis going forward.
Marco Polo Deepwater TLP
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 95331, "Marco Polo Deepwater TLP: Completion Implementation and Performance," by J. Burman, SPE, Exploitation Technologies LLC, and K. Renfro, SPE, and M. Conrad, SPE, Anadarko Petroleum, prepared for the 2005 SPE Annual Technical Conference and Exhibition, Dallas, 9–12 October.
Novel well-completion techniques and exceptional field execution allowed the six well completions in the Marco Polo deep-water tension-leg-platform (TLP) project to be accomplished in world-class fashion. All six wells (17 frac packs) were placed on pro-duction in only 168 days, including 14 days lost because of storms. The full-length paper focuses on how the implementation challenges of completing 17 zones in six deepwater dry-tree wells with a 1,000-hp rig were met and highlights a number of concepts and technical firsts that can be used in other deepwater development projects.

Background
Field Development. The Marco Polo field in Green Canyon Block 608 in the Gulf of Mexico (GOM) was discovered in 2000. Six development wells were drilled in 2002 and 2003 and were temporarily abandoned to await completion of the TLP. The TLP hull and deck were installed in January 2004 and were designed to accommodate a 1,000-hp completion rig to run riser tiebacks and perform completions. Only 88 persons are allowed on the platform at a time because of U.S. Coast Guard rules, a significant issue for rig operations.
Reservoir. Initial reservoir pressures and temperatures range from 6,700 to 7,600 psi and from 115 to 122°F, respectively. Reservoir fluids are undersaturated black oils, with gravity ranging from 30 to 34°API and gas/oil ratio ranging from 700 to 1,000 scf/STB.
Completion-Design Overview. Multiple pay sands, low reservoir temperatures, the requirement to gas lift the wells, and the deepwater environment drove the design of the Marco Polo completions. After significant flow-assurance modeling and evaluation, dual-barrier risers with insulating gel and a separate gas lift string were chosen as the upper-completion design.
The sandface-completion design focused on risk management during completion operations, with the hardware designed to minimize future intervention risk. The 17 pay intervals in the six wells were developed with multizone, selective single, stacked frac-pack completions, using sliding sleeves with a concentric isolation string for zonal isolation.
Multiple chemical-injection points are installed for hydrate, paraffin, asphaltene, and scale prevention. The installation of fiber-optic technology for downhole-pressure and -temperature sensing assisted in well surveillance and hydrate prevention. Fig. 4 in the full-length paper shows a generalized Marco Polo wellbore schematic.
Economic and Operational Benefits of Drill-Through Completion Technologies
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 17405, "Economic and Operational Benefits of Drill-Through Completion Technologies," by M. Matusek, S. Stjernstrom, and D. Theiss, Cooper Cameron Corp., prepared for the 2005 Offshore Technology Conference, Houston, 2–5 May.
The drill-through completion concept revolves around the principle that substantial cost savings can be realized by installing the subsea horizontal tree before running the blowout preventer (BOP) stack, thus eliminating one BOP stack round trip. Drilling operations are performed through the subsea horizontal tree. Additional cost savings can be achieved in a batch-drilling and -completion program by reducing the number of required rig moves and BOP-stack trips.

Introduction
Interest in drill-through systems has increased in recent years as oil companies search for ways to reduce installation and workover costs associated with deepwater drilling and completions. As water depth increases, time required to deploy equipment to the seabed and the day rate of a rig capable of operating in deeper waters increase. As a result, the value of reducing deployment trips and improving operations reliability increases.
The horizontal subsea tree has had a large influence on the way completion and workover operations are conducted. Drill-through technology allows some or all of the drilling operations to be conducted through the tree—providing numerous opportunities to save time and money, particularly in deepwater operations.

Benefits
The conventional approach to drilling and completing wells involves two round trips of the BOP stack. The drill-through approach to drilling allows the horizontal tree to be installed on top of the wellhead high-pressure housing before running the BOP stack, so that all drilling operations are performed through the tree. The tree is capable of drifting all of the drill bits, casing hangers, seal assemblies, and associated running/test tools required during the drilling and wellhead-installation process. This drilling and completion method requires only a single BOP-stack trip. By eliminating one of the round-trip BOP-stack deployments, substantial cost savings can be achieved.
For a rig operating in 6,000 to 8,000 ft of water, deployment of the BOP-stack and drilling-riser system is estimated to require 4 to 5 rig days. Another 8 to 12 hours are required to test the BOP-stack connections, functions, and control system once it is landed. BOP-stack retrieval is estimated to require 3 days of rig time. With the cost for deepwater rigs estimated to be U.S. $180,000 to $240,000 per day, the estimated cost to make one BOP-stack and riser-system round trip is U.S. $1,300,000 to $2,000,000. This cost may be significantly higher if poor weather conditions delay operations.
Clair Field, West of Shetland
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 97772, "Unlocking the Potential: A North Sea Heavy Oil Success Story," by J.J. Wylde, SPE, and G.D.M. Williams, SPE, Clariant Oil Services, and R.E. Cousins, BP plc, prepared for the 2005 SPE International Thermal Operations and Heavy Oil Symposium, Calgary, 1–3 November.
The full-length paper details one of the newest producing fields in the North Sea, the West of Shetland development. Prestartup design and implementation challenges are described, as well as commissioning philosophy for the plant and chemical-injection facilities. Most of the full-length paper focuses on the first 6 months of production history, production-technology management, and how actual operation differed from the planned and designed specifications.

Clair Field Background
The Clair field is 40 miles west of the Shetland Islands and currently is produced from a single fixed platform in 460 ft of water. The field produces both oil and gas. The field produces 20°API crude with a 550 scf/bbl gas/oil ratio. The Clair reservoir extends over a 25×12.5-mile area in complex Devonian and Carboniferous units covering five license blocks. Current estimates of likely oil exceed 4 billion STB original oil in place (OOIP), making Clair the largest undeveloped hydrocarbon accumulation on the U.K. continental shelf and a key component of future U.K. production stategy.
The Clair field was discovered in 1977. In the early 1990s, 3D-seismic data were acquired over the whole field, and two wells were drilled in 1991 and 1992. Although demonstrating commercial flow rates, the wells were not produced for sufficiently long to provide confidence in long-term reservoir performance. In 1996, an extended performance test was conducted on Well 206/8-10z in the core area. Flowing at an average rate of 10,000 B/D for 23 days, with a 18.5-B/D peak, the well performance changed the perception of the Clair reservoir by demonstrating sustainable crude-oil delivery.
Because of its extent, the Clair field is to be produced as a phased development. The first phase builds on the successful 1996 well test and targets development of the Core, Graben, and Horst areas. The reservoir is divided into nine fault-bounded segments having a common free-water level and 1,969-ft maximum oil column. A gas cap is present in the structurally elevated ridge segments. The reservoir depth is 6,070 ft true vertical depth subsurface, and initial reservoir pressure was 2,736 psi with a 151°F temperature. Work is continuing to define this first development. The challenge for Clair is understanding the issues of reservoir deliverability, well productivity, and managing the cost base while achieving a sustainable development. Clair will be the third West of Shetland development, following Foinaven and Schiehallion.
New Logging Tool Enhances Multiphase Production Analysis
Authors: JPT staff _ 
Published: February 2015

A new multifunction production logging (PL) platform is producing quantifiable results in complex triphasic flow regimes. At 25 ft long, the system takes the place of a conventional PL tool string five times as long. The Schlumberger Flow Scanner tool, unlike its predecessor, features close integration of its 17 sensors in an 11-ft-long sonde so that true dynamic flow characteristics can be obtained at any point in the well. The new system is designed to operate in wellbore diameters ranging from 2 7/8 to 9 in. and under environmental conditions up to 300°F and 15,000 psi. This technology is particularly valuable in deviated and horizontal multiphase wells, where phase behavior is extremely variable and complex. To obtain an accurate picture of the dynamic flow regime at any point in the well, it is necessary to scan the full diameter of the wellbore. The new logging tool does this mechanically, electrically, and optically. (Fig. 1).
Run eccentered in open or cased holes, the tool finds the low side of the hole thanks to gravity. Then an articulated sensor arm is deployed that spans the wellbore, providing five equally spaced measurements of flow velocity, direction, and phase fraction. Together, these measurements provide three-phase holdup, which is defined as the dynamic phase fraction at any point in the wellbore. Holdup differs from produced volume fraction, or cut, because the phases travel at different velocities. Other tool sensors measure pressure and temperature, hole diameter, and instantaneous tool orientation.
To analyze a production interval properly, one must understand exactly what is happening at each spot in the wellbore. Previous PL methods interfered with the flow regime they were trying to measure, and typical phenomena such as heavy-phase recirculation resulted in ambiguous data with gaps over critical intervals. In addition, interpretation could take months and involved dozens of specialists examining data from several log passes. In contrast, the new logging tool was designed using computational fluid-dynamics simulations to optimize its shape and minimize any flow perturbations. A real-time graphics display and processing workflow makes preliminary interpretation possible with a single logging pass. One or two additional passes at different logging speeds can enhance overall accuracy.