bluuebunny/crossref_metadata_2025_split huggingface dataset:
Emerging Frontiers: Frontiers in Technology Dissemination
Authors: Spath Jeff 
Published: February 2015

President's column
I must write my final column, before next month’s recap, on the most fundamental mission of SPE, our core purpose, our raison d’etre: the dissemination of technology. More precisely, I am talking about the part SPE plays in the dissemination of independent, unbiased, trusted, and reliable technical information and knowledge. SPE is recognized worldwide for its role in this area and it is the topic that makes up the heart of our mission statement, which incidentally has not changed in 35 years.
The rationale for quality technical information dissemination and knowledge sharing is at least twofold. Firstly, for individual members to progress in their career and take on more challenging roles of increasing responsibility, they must develop, maintain, and improve their skills and expertise through knowledge sharing and by having access to quality, reliable technical information. Secondly, the value proposition of most companies in our industry hinges on the technical expertise of its people, so it is necessary to continually develop employee expertise as a competitive advantage. A large part of this development comes from SPE-provided literature, training, and knowledge gained from conferences, workshops, and forums.
Many of our knowledge domains are undergoing rapid change, which elevates the importance of SPE’s ability to share technical information and knowledge in a timely manner. Deepwater exploration, shale gas and shale oil production, subsea development, and heavy oil recovery are a few examples of subjects for which yesterday’s technical information is inadequate. The globalization and remoteness of our industry’s workforce is another reason we must continually advance the ways in which we distribute technical information. Finally, the retirement of many of our longest-tenured experts requires that we accelerate the learning of the younger professionals and the efficient dissemination of quality technical information is the key.
Technical Quality
If your mission and livelihood is to disseminate technical information, the quality of the information is paramount and must override any measure of timeliness, affordability, accessibility, or availability. If you do not have the utmost confidence in the quality of the technical information or the knowledge being shared, it does not matter the user-friendliness of getting the information. There is no doubt that the number of technical presentations and papers being written has grown rapidly over the last decade, tied to the significant growth in the number of conferences and workshops.
Comments: Reader Survey
Authors: Donnelly John 
Published: February 2015

Editor's column
Last month, JPT concluded its annual readership survey to assess SPE members’ opinions of this magazine’s content, coverage, relevance, strengths, and weaknesses. The information will be used to improve JPT’s quality and to help plan content for the coming year. An invitation to participate in the survey was sent to a random sample of 30,000 professional (non-student) members, representative of the demo-graphics of SPE. Of the respondents, 44% reside outside the US, 82% of them have more than 10 years of experience in the oil and gas industry, 40% are engineers, and 24% are managers. Responses came from members who work for operators, national oil companies, service companies, and consultancies.
The most widely read features in JPT are Technology Update, the summaries of technical papers, and Technology Applications, highlighting our readers’ interests in emerging technology, practical deployment of technology, and case studies. This also confirms results from previous readership surveys. Regarding specific technical topics, respondents expressed the most interest in field development projects, mature fields and well revitalization, and horizontal and complex trajectory wells.
Looking at some other findings, the overall ranking of JPT rose compared with previous surveys. In this year’s survey, 95% of respondents rated JPT as excellent, very good, or good and 77% rated JPT better or significantly better than other upstream publications, up from 65–70% in previous surveys over the past decade. Just under 90% of readers said JPT was useful to them in their daily job.
The summaries of SPE technical papers in JPT have always ranked near the top in readers surveys. JPT’s 42-person Editorial Committee—made up of volunteer members representing all facets of the upstream oil and gas industry—survey scores of technical papers every year for possible publication. Last year, the committee pored over 3,138 technical papers before selecting the final ones for publication in JPT. Their work results in the publication of approximately 130 papers over the course of the year in 42 different upstream technical topics, the best papers representing the state of the art in a particular technology. The summaries of those papers appear in each issue, while the full-length papers are available free to members for 2 months at JPT Online.
Speaking of JPT Online, our website has a new look and a new address (www.jptonline.org). The website was redesigned based on the results of reader surveys, a focus group, and industry trends. The revitalized site contains more news and more in-depth coverage of emerging technologies and the latest technology applications, with articles organized by discipline and region, and has a new search engine. Members can continue to download the free technical papers summarized in JPT as well as view the print archives at the site. Please let us know what you think of the changes.
Eni Makes Its Mark
Authors: Donnelly John 
Published: February 2015

Editor’s note: This is the third in a series of profiles of leading operators, including key international and national oil companies, around the globe. The focus is on the company’s strategic direction, relationship to its government, major upstream activity, and significant technology challenges and applications.
Italian energy giant Eni plans to meet ambitious future growth targets with a strategy focused on conventional reserves, quick time to production, and continued success in Africa.
Eni is a major integrated energy company, involved in oil and gas, electricity generation, oilfield services construction, and engineering, but its future lies largely in E&P. It has bulked up its reserve base this decade and hopes an upstream strategy based on speeding up production time will pay off over the next several years as new fields come on line.
Total oil and gas production for Eni is flat so far this year and fell last year, putting pressure on the company to fast-track output. For the first half of 2010, total oil and natural-gas production amounted to 1.77 mil-lion BOEPD, a decrease of 28,000 BOEPD from 2008, although much of that can be attributed to OPEC cuts that affected its operations in those countries. Weak European gas demand, security issues in Nigeria, and mature-field declines also hurt production, but that was partly offset by production increases and field startups.
Leveraging organic growth in Africa and Central Asia, the company plans to deliver more than a 2.5% average growth rate over the next 4 years, targeting total production levels of more than 2 million BOEPD by 2013. A total of 41 projects worldwide are scheduled to come on line by 2013, some in countries with a recent past of political risk.
Eni claims a total of 30 billion BOE in total resources, a base built in recent years through exploration, access to giant fields, and a few acquisitions. Most of those reserves are in legacy areas, where Eni is a leading operator, and are considered conventional, low-cost plays. The firm says its priority in the short to medium term is to expedite the development of this potential through a new organization model focused on bringing production on line as quickly as possible. It aims to increase its recovery factor, which currently is 34% for oil and 65% for gas.
Technology Focus: Completions Today (September 2010)
Authors: Horvat Damir 
Published: February 2015

Technology Focus
Making the Good Completion Better
The ability of operating and service companies to optimize completion results from standard completion configurations through better reservoir-fluid management has been enhanced greatly by the development of advanced completion hardware [i.e., inflow-control devices (ICDs)]. These devices enable us to “fine tune” flow from individual pay zones that are over- or underpressured. Field performance of wells equipped with ICDs and multisegment-well modeling, including ICDs, have indicated measurable advantages over conventional completion systems. Industry also developed perforating-gun modules that can be configured to perforate the formation in any desired orientation. As each gun module is fired, a flapper valve is actuated to isolate the newly created perforations from the lower, previously stimulated zones. This process ensures accurate and efficient proppant placement.
An operator’s goal is to reach production faster, with the widest assortment of specialty tools and hardware, which have been improved continuously over the past decade. Today, many operators use multilaterals, which enable maximum reservoir contact with minimum surface requirements and can accommodate a wide range of completion options. Whether the play is a conventional shallow-gas or deep-gas reservoir or an unconventional-oil/-gas reservoir, use of these technologies can increase production while improving project economics. Reliable and field-proven completion solutions enable creating the ideal conduit from pay zone to surface, regardless of well type or operating environment. This is the key to getting the greatest return on field-development investment and to minimizing life-of-well cost.
This overview will not attempt to refer to all new well-completion technologies, but only to highlight a few important recent developments and concepts. Nevertheless, as one searches the literature, the importance of JPT’s role becomes obvious from the large number of references and papers cited with relevance to significant technical achievements in the upstream petroleum industry. There are many papers about technological advances, and I congratulate respective authors in bringing their papers to fruition.
Finally, I hope you enjoy reading the selected papers as much as I did during review and selection for the feature.
Completions Today additional reading available at OnePetro: www.onepetro.org
SPE 125508 • “New Approach to Drilling and Completing Horizontal Wells in Extremely Shallow and Unconsolidated Reservoirs” by Shahryar Saebi, SPE, Schlumberger, et al.
SPE 122765 • “World’s First Reverse-Port Uphill Openhole Gravel Pack With Swellable Packers” by Rene Jansen, Brunei Shell Petroleum, et al.
SPE 128569 • “Integrated Approach: Perforation-System Optimization for Sand Prevention” by Mohd Zahirin B. Ruslan, SPE, Schlumberger, et al.
Monobore Completion System Provides Low-Cost Completion Option
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 124797, ’Monobore Completion System Provides Low-Cost Completion Option,’ by Don Ingvardsen, SPE, and Jim Kritzler, SPE, Baker Hughes, originally prepared for the 2009 SPE Annual Technical Conference and Exhibition, New Orleans, 4-7 October. The paper has not been peer reviewed.
Many wells completed today could be classified as short-life or harvest wells. Some of these would not be economically feasible using high-end completion components and methods. Monobore wells can be a solution to this problem. The full-length paper discusses several methods in which monobore well design can save considerable time while lowering the overall completion cost.
Introduction
When a well has a single produc-tion-tubing size from the pay zone to the surface of the completion, it is categorized as a “monobore” comple-tion. Although there are certain limita-tions to this type of completion, there are many advantages that make it a very attractive alternative to conven-tional completions. Drilling cost and reduced equipment list are the great-est motivators to pursue a monobore well because they directly affect the cost to complete. Most of these wells would not have been feasible if the only option was to complete them in a more traditional manner. However, if there were a system that reduced rig time and decreased the equipment list (e.g., packers and sliding sleeves), while still safely completing the well, these wells would move from the category of unfeasible or marginal to profitable or, in some cases, highly profitable. One of the early methods was simply cementing the completion in the well-bore. Later options include staging the cement process to include equipment that would increase the life of the well and ensure its safe operation.
Significant time and effort have been expended to develop a more reliable system for completing these wells and increasing their productivity, making them even more attractive. Specially designed cement-through components, including safety valves and gas lift (GL) equipment, can be credited with mov-ing these monobore completions to the next level. The inclusion of a reli-able safety valve speaks for itself with regard to producing these wells safely, but introducing the GL alternative at the beginning has increased the over-all production significantly. Wells that were estimated to produce 500 to 600 B/D were improved to 1,200 to1,400 B/D. The majority of these completions have been completed in the Gulf of Thailand, but there are other fields in the world that are candidates for this system, and equipment has been mobi-lized to some of those areas.
Increasing Drilling Efficiencies Through Analysis of Real-Time and Historic Drilling Data
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 128722, ’Increasing Drilling Efficiencies Through Improved Collaboration and Analysis of Real-Time and Historical Drilling Data,’ by Catheryn Staveley, SPE, and Paul Thow, SPE, Schlumberger, originally prepared for the 2010 SPE Intelligent Energy Conference and Exhibition, Utrecht, The Netherlands, 23-25 March. The paper has not been peer reviewed.
Estimated spending on drilling and completions was more than USD 250 billion in 2008. With rig costs estimated to consume 37% (or USD 92.5 billion) of that spending, every effort to reduce drilling time has a direct effect on the bottom line. Estimates of nonproductive time (NPT) ran from 15 to 40%, or USD 14 to 37 billion, depending on well type and operator. The causes were varied and included technical and nontechnical challenges. Obviously, any effort made to reduce NPT will affect bottom-line spending.
Introduction
The oil and gas industry spends millions of dollars each year collecting vast amounts of drilling data, yet has not made effective use of these data to improve drilling performance. Drilling analysis is a proven technique for improving the return on investment of drilling operations, but comprehensive drilling analysis has not been a regular part of well planning and operations.
So why is it that comprehensive drilling analysis is not a consistent part of drilling best practices? In part, perhaps, because of the culture. One author suggested that 95% of drilling activities are operationally focused, placing emphasis on doing, rather than planning or analyzing. Many people in drilling operations thrive on operating by “gut instincts” and succeeding through heroic efforts. While experience dealing with unexpected events is crucial for success in an environment where uncertainty exists, surely it would make more sense to be taking pride in telling stories about the well where everything went according to plan. Furthermore, while most companies have health, safety, and environmental policies that are “zero-tolerance,” an acceptance of waste and inefficiency as being inevitable in drilling operations continues. It is difficult to imagine another industry that would accept 60% waste when it is widely known that something as simple as better planning can improve drilling results.
Two other key obstacles to integrated drilling analysis are the inability to manage the volumes of data that potentially could be used in drilling analysis and the historical limitations of traditional well-planning software. The vision for integrated drilling analysis includes the ability to:
Visualize and correlate low- and high-density data.
Allow effective sharing of cross-discipline expertise.
Provide continuous real-time updates.
This integrated approach includes technologies to overcome data-management challenges and well-planning limitations, and to implement multi-disciplinary work flows to help facilitate planning and analysis across an asset team.
Evolution From Casing Running to Assurance of Total Depth
Authors: Cummins Tracy 
Published: February 2015

Technology Update
Well construction, hazard mitigation, and drilling equipment have evolved significantly over the past 10 to 15 years. One of the most critical aspects of well construction is assuring that casing strings are installed to the planned depth with gas-tight connections and sound mechanical barriers between them. The widespread acceptance of top drive casing running and drilling with casing have played a key role in recent developments to the delivery of high-integrity casing strings.
Top drive casing running tools attach to the rig’s top drive and combine many conventional casing tools into one sys-tem. They extend the functionality of the rig’s top drive from drill pipe to casing, thus enabling simultaneous rotation, reciprocation/push down, and circulation of the casing string. Adding a reaming shoe or drillable casing bit to the casing string makes it possible to ream in a pre-drilled section, extend through problem zones or drill complete hole sections with the casing string. This addition opens a broad range of options to increase drilling efficiency and reduce nonproductive time.
Technology Expands Top Drive Applications
Top drive casing running systems first came into use in the 1990s. Initially, these systems were used primarily on purpose-built casing drilling (land) rigs. Soon after early deployments, the technology became an accepted way to run casing. However, its use was still limited to land rigs and running API threaded tubulars.
By 2005, further development of the technology portfolio included equipment designed to accommodate a broad range of applications such as:
Offshore rigs—casing sizes up to 22 in., torque up to 80,000 lbf-ft
Premium connections—independent torque monitoring and active weight compensation
Heavier casing strings—hoisting capacity up to 750 tons
Running casing in stands—interfacing with pipe handling and rig control systems
High-angle and ultraextended-reach wells—pushing, rotating, and floating casing strings
Chrome tubing completions—minimal marking systems and torque control interface
During this time, the equipment for drilling with casing and casing connections also evolved, with the development of a number of drillable polycrystalline diamond compact casing bits and higher torque- and fatigue-resistant connections to cope with various formation strengths and geology.
Today, these technologies are field proven in a number of applications and readily available across the globe. Thousands of casing strings have been run or reamed by means of the top drive system, and more than 2,000 problem zones or well sections have been successfully drilled with the casing string.
Joint Venture Challenges Drilling's Status Quo
Authors: Rassenfoss Stephen 
Published: February 2015

Shell is facing up to fast-rising future drilling costs by taking control, with a venture that will build, own, and operate drilling rigs. The company has created a joint venture with China National Petroleum Corporation (CNPC) to build a new generation of special-purpose automated drilling equipment.
There is a back-to-the-future quality about the strategy. Oil companies once owned many of the rigs used to drill their wells, but largely got out of the business in the 1970s and 1980s as they pared back to focus on the more profitable business of finding oil and gas.
Shell is changing its strategy as the number of wells it drills soars to take advantage of unconventional reserves. For example, rather than drilling 10 highly productive wells to develop an offshore field, Shell expects to drill about 10,000 wells to produce natural gas from a single coalbed methane project
“The well manufacturing joint venture is an opportunity to redefine our costs in an area where we spend a significant amount of money,” said Peter Sharpe, executive vice president of wells at Shell.
Shape declined to say how much Shell expects to invest or benefit from the venture. The agreement was signed between the companies in late June. As of late July the two sides were working on a detailed business Sharpe plan and negotiating details, such as what intellectual property each would contribute. The operation, which has not yet begun design work, expects to begin production in 2013.
The venture is not going to become the driller of choice on all Shell projects. It is aimed at fields requiring high-density drilling, with thousands of wells drill over decades. Fields that do not fit into that category include Shell’s US shale holdings, where the drilling is not on the scale needed for its high-density field approach.
The business plan for Shell’s manufactured drilling program goes after costs in a variety of ways. It combines new technology—drilling automation—with long established cost-cutting strategies: partnering with a low-cost provider, economies of scale, specialization, and cutting out the middleman.
Shell’s partner in China, CNPC, is a major maker of drilling rigs in one of the world’s largest and most efficient manufacturing economies. While Shell is far better known, Sharpe said CNPC’s budget for drilling and completing wells is comparable to its own.
The automated drilling program is expected to lower costs by drilling wells faster with fewer people on site, which should make it safer as well. It reduces the number of rig workers, who are hard to find in some territories. Sharpe said there are countries where “we can’t train the people we need at the rate we need them.”