bluuebunny/crossref_metadata_2025_split huggingface dataset:
Periodontal Soft Tissue Non–Root Coverage Procedures: Practical Applications From the AAP Regeneration Workshop
Authors: John Vanchit , Langer Laureen , Rasperini Giulio , Kim David M. , Neiva Rodrigo , Greenwell Henry , Dibart Serge , Sanz Mariano , Scheyer E. Todd 
Published: February 2015

Focused Clinical Question: What are the indications and clinical applications for gingival augmentation procedures, and what factors guide the choice among treatment options in specific situations?Summary: Although there is still controversy regarding whether there needs to be a minimum amount of attached gingiva to maintain the stability of the gingival margin, prospective and retrospective studies have shown that, in the presence of suboptimal plaque control and clinical inflammation, attachment loss and gingival recession (GR) may result unless a minimum amount of keratinized tissue (KT) and attached gingiva are present. Treatment of mucogingival deformities requires gingival augmentation procedures that address both a functional and esthetic component for the patient. Although free gingival grafts (FGGs) are considered the gold standard for treatment of GR defects to obtain root coverage, augmentation of KT and attached gingiva may be accomplished by FGG or other autogenous grafting options, including the free connective tissue graft, the lateral pedicle graft, and the double papilla technique. In addition, the modified apically repositioned flap can be considered in some instances. Alternatives to autogenous graft tissue include acellular dermal matrix, extracellular matrix membrane, bilayer collagen matrix, and living cellular construct.Conclusions: Understanding the clinical importance of the presence of a minimum amount of attached gingiva in patients with suboptimal hygiene is an important first step in addressing the condition. Patient education to address plaque control and counseling to quit smoking in patients who are smokers help enhance the success of these mucogingival surgical procedures. An analysis of patient‐specific factors will help with the appropriate choice of surgical procedures aimed at augmenting the dimension of KT/attached gingival tissue. Evidence supporting the treatment decisions described in this practical application is summarized in the companion papers from the American Academy of Periodontology Regeneration Workshop (Kim and Neiva, J Periodontol 2015;86(Suppl.):S56‐S72; Scheyer et al., J Periodontol 2015;86(Suppl.):S73‐S76).
Emerging Regenerative Approaches for Periodontal Reconstruction: Practical Applications From the AAP Regeneration Workshop
Authors: Rios Hector F. , Bashutski Jill D. , McAllister Bradley S. , Murakami Shinya , Cobb Charles M. , Patricia Chun Yong‐Hee , Lin Zhao , Mandelaris George A. , Cochran David L. 
Published: February 2015

Focused Clinical Question: Can emerging technologies for periodontal regeneration become clinical reality?Summary: Emerging technologies are presenting options to hopefully improve the outcomes of regeneration in challenging clinical scenarios. Cellular allografts represent a current technology in which cells and scaffolds are being delivered directly to the periodontal lesion. Recombinant human fibroblast growth factor 2 and teriparatide (parathyroid 1‐34) have each been tested in controlled prospective human randomized clinical trials, and both have been shown to have potential for periodontal regeneration. These examples, as well as other emerging technologies, show promise for continued advancement in the field of periodontal regenerative therapy.Conclusions: At present, there are indications that emerging technologies can be used successfully for periodontal regeneration. Case reports and clinical trials are being conducted with a variety of emerging technologies. However, many are yet to be approved by a regulatory agency, or there is a lack of evidence‐based literature to validate their expanded use.
Periodontal Regeneration — Furcation Defects: Practical Applications From the AAP Regeneration Workshop
Authors: Aichelmann‐Reidy Mary E. , Avila‐Ortiz Gustavo , Klokkevold Perry R. , Murphy Kevin G. , Rosen Paul S. , Schallhorn Robert G. , Sculean Anton , Wang Hom‐Lay , Reddy Michael S. 
Published: February 2015

Focused Clinical Question: How should periodontal furcation defects be managed via periodontal regenerative therapy, and what parameters should be used for treatment selection?Summary: The treatment of furcation defects can vary based on the type and location of the furcation involvement. Attaining predictable regenerative outcomes is dependent on the control of local and systemic factors. A combined treatment approach (barrier and bone replacement graft with or without biologic) generally offers the better therapeutic outcome over monotherapy. Class I furcation defects can be managed via conventional periodontal non‐surgical and/or surgical therapy, whereas Class II furcation defects generally attain better outcomes with regenerative therapy. There is weak evidence, limited to case reports, that Class III furcation defects can be treated successfully with regenerative therapy.Conclusions: In Class I furcation defects, regenerative therapy might be beneficial in certain clinical scenarios, although most Class I furcation defects can be treated successfully with non‐regenerative therapy. For successful treatment of maxillary and mandibular molars with Class II furcation defects, systemic and local factors should be controlled, and surgical debridement and postoperative maintenance should be performed adequately. Although there is limited evidence for regeneration of Class III furcation defects, there may be a modest improvement allowing for tooth retention. Ultimately, the benefit of tooth retention and cost should be considered in the indication of therapy for teeth with severe furcation involvement.
Technology Update: Distributed Fiber-Optic Technologies Drive New Intervention Applications
Authors: Gardner Neil , Hveding Frode , Sambrook Roger 
Published: February 2015

Technology Update
Downhole data acquisition by fiberoptic technology, particularly distributed fiber-optic (DFO) sensing, has gained rapid acceptance. Compared with conventional data acquisition, DFO provides a much better understanding of well and reservoir behavior. Reflecting this trend is the increasing number of well completions equipped with permanent fibers.
However, many fibers have been installed only above the production packer and thus are unable to monitor the dynamic changes in the reservoir. During the past several years, Ziebel has developed well intervention technologies for obtaining DFO data from wells without permanent fibers, wells in which fiber installations end above the production packer, and wells in which installed fiber systems have failed.
The company offers two methods of collecting this data. They are as follows:
The Z-System consists of a composite carbon rod, 15 mm in diameter, containing multiple fiber-optic cables. The rod is safely injected into producing or injecting wells. It is semi-stiff and can achieve a long reach into horizontal wells in an installation similar to conveyance by a light coiled-tubing (CT) string without the need for a well tractor.
The new gravity-deployed Z-Line is a composite carbon line, 4.8 mm in diameter, that is designed to be run on wireline units. Its DFO sensing capability is equally effective in all well sections from vertical to highly deviated. However, its extremely high strength-to-weight ratio, coupled with its low friction coefficient to steel and extra stiffness compared with wireline, enhances its reach into highly deviated sections (Fig. 1).
So far, the data obtained by these two technologies have been used largely for water and polymer injection allocation, optimizing production, or for monitoring well integrity. Looking ahead, the company plans to expand the use of these technologies to monitor sand production and downhole injection processes in real time to assess stimulation efficiency. Improving the interpretation of DFO data remains a major focus.
Identifying Sand Ingress Zones
Existing techniques for detecting produced sand are primarily limited to surface detection by acoustic sensors. While sufficiently accurate and timely to warn of a developing problem downhole, these methods are unable to determine the depth from which the sand originates, an essential factor for planning remedial treatment.
A Competency Management Tool for SPE Members
Authors: Jain Alok , Ogle Ken 
Published: February 2015

Talent & Technology
To meet one of SPE’s strategic priorities, capability development, the Society has partnered with International Human Resource Development Corporation (IHRDC) to offer the SPE Competency Management Tool (CMT) free to its members. The tool can be used to assess the competencies needed to perform specified key technical jobs in the oil and gas industry.
Based on assessment results, the tool will identify competency gaps and help members develop individual learning plans to close these gaps. Learning plans will refer users to SPE training resources, along with resources offered by sister organizations, such as the Society of Exploration Geophysicists (SEG) and the American Association of Petroleum Geologists (AAPG), and also to generic course titles reflecting those offered by third-party course providers.
In developing a learning plan, the user will be able to choose priorities for closing competency gaps, select the most appropriate learning resources, and determine the pace at which learning should take place. The SPE CMT will give the user flexibility and a chance to take ownership of his or her professional development. Employers, meanwhile, will benefit from the consistency in skills and improved productivity that their employees are able to achieve.
The “pilot” status of the SPE CMT is designed to gauge the level of interest for a service of this nature. Upscaling the tool to its full scope of service will require significant investment in time and resources, which can be justified only if the results of the pilot validate the need for such a level of service.
Published global trends show an ever-increasing demand for professional development of the workforce to meet future energy needs. That, along with the recognition that the onus of personal development in the oil and gas industry today rests largely with the individual, should be sufficient justification for such a service. However, one cannot ignore the fact that major oil and gas companies, including many national oil companies, have been preparing for the “big crew change” for some time and have developed in-house capabilities for competency assessment and development.
Competency development, certification, and training activities are not new to SPE, which was a forerunner in recognizing the need for competency guidelines to define minimum aptitude levels for petroleum engineers and establish future industry standards. These competency guidelines are in place today on the SPE website.
Decommissioning Costs Can Be Reduced
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 25247, ’Decommissioning Costs Can Be Reduced,’ by Alan William Stokes, SPE, WorleyParsons, prepared for the 2014 Offshore Technology Conference, Houston, 5-8 May. The paper has not been peer reviewed. Reproduced by permission.
Many offshore decommissioning costs are higher than necessary because of decisions made during the initial engineering and construction for an oil or gas field. Economics for a 60,000-BOPD oil field show that a reduction in decommissioning costs of 50% can increase the project net present value (NPV) by 13%. A 5-year range of decommissioning data collected from throughout the world has been studied. Key areas have been identified in which decisions made during design affected the eventual decommissioning costs.
Introduction
Decommissioning/removal of an offshore platform in 100 m of water is a complex project. Decommissioning of a platform in a severe environment can cost hundreds of millions of GBP. New-development project teams need to spend as much effort preparing for decommissioning in the design stage as they do preparing for the maintenance of the platform.
Costs can be reduced during the actual decommissioning work by application of a contracting strategy and the use of previous experience and new technology. However, many costs are fixed because of the design features of the fixed platform or compliant structure. This paper provides guidance on how to engineer for decommissioning during the design stage of a new project.
Project Economics
The cost of decommissioning has to be included in the cash flow of the development because the late-life production rate is included. A typical North Sea platform in 80 m of water for a throughput of 65,000 BOPD with a 15-year field life has a cash flow that starts negative, turns positive, and then ends negative with decommissioning (Fig. 1). The final decommissioning cost before tax refund was estimated to be GBP 800 million.
If the decommissioning cost can be reduced, the NPV of the project will be increased. Results of four NPV calculations as the decommissioning cost was reduced from GBP 800 million to 200 million are shown in Fig. 2. In halving the decommissioning cost from GBP 800 million to 400 million, the NPV of the project increases by 13%. These calculations assume a major short-term cash expenditure with the facilities being decommissioned using cash-intensive methodologies over 1 year. Other operators might want to design their new facilities to be decommissioned over a 4-year period at reduced cash flow, with consideration given to the knock-on effects of keeping utilities and the accommodation operable for the 4-year period.
Significantly, the extended decommissioning project has an increase on the NPV of 30% because of the discount rate being applied to the decommissioning costs over 4 years rather than 1 year. When this 30% is added to the 15% increase resulting from cost reduction, the project NPV improves dramatically.
Connecting With Stakeholders
Authors: Eberhard Mike , Olsen Robin 
Published: February 2015

Beyond the Headlines
Colorado recently has been at the epicenter of the energy debate. The oil and natural gas industry has been facing unrelenting scrutiny from activist groups and concerns from stakeholders about operations in an urban environment. The Wattenberg field, located 25 miles northeast of Denver, has been an active field for more than 50 years and has more than 15,000 vertical wells. But the increased visibility associated with recent horizontal well activity, combined with the area becoming more densely populated, put the operations in the spotlight.
The industry has traditionally done a poor job of communicating information in a meaningful way that resonates with stakeholders. As engineers, we like to use science, data, and charts to explain things to people, but in this case it was not working. There was a need to enhance and reengineer communications and engagement with all stakeholders.
Anadarko Petroleum recognized this need to change how the industry has traditionally interacted with the public, including the Colorado communities where it operates. Beginning in 2012, using its five core values as a guide, Anadarko began an initiative to create ambassadors out of its most valuable asset: its employees. The five core values are:
Integrity and trust
Servant leadership
People and passion
Commercial focus
Open communication
The development of any company strategic tool or practice must align with these values and, in this case, the enhancement of open communication in Colorado was the central focus. Giving employees the tools and resources to have educated and respectful dialogue about responsible oil and natural gas development empowers them to listen and confidently address questions and share the benefits of the energy industry.
Anadarko’s public affairs and government affairs teams created and implemented an internal communications campaign known as the Anadarko Ambassador Program. The components of the program include:
A printed ambassador tool kit containing industry statistics
Facts and talking points
A 3-day “advocate” training program for employees
A 1-day “ambassador” training
A mobile app for electronic devices called the Ambassador App
New Cement Spacer Chemistry Enhances Removal of Nonaqueous Drilling Fluid
Authors: McClure Jason , Khalfallah Ines , Taoutaou Salim , Vargas Bermea Jorge Andres , Kefi Slaheddine 
Published: February 2015

Technology Update
An efficient removal of drilling fluid is essential to successful cementing operations. When a cement slurry comes into contact with mud residue, the cement may not set properly or adhere to the casing and formation, thereby preventing the isolation of permeable zones under different pressure regimes. This can cause stimulation out of zone, production of unwanted fluids because of communication between zones, loss of hydrocarbons into lower-pressure formations, corrosion of casing, and blowouts. In recent years, the industry has focused considerable attention on enhancing cementing practices to ensure well integrity and zonal isolation.
To clean all well surfaces after the placement of casing, an intermediate water-based fluid, or spacer, is pumped between the drilling fluid and cement slurry. Typically, a package of surfactants or solvents is added to the spacer to improve cleaning and displacement efficiency.
However, over the past decade, spacer formulations have not evolved as rapidly as the chemistry of drilling fluids. Every year, operators drill deeper, more complex, and higher-temperature wells under a growing range of downhole conditions. To boost performance, drilling fluids incorporate a greater variety of nonaqueous fluids (NAFs) based on synthetic and natural oils—mineral, paraffinic, and olefinic oils—with much longer carbon chains than traditional diesel-based muds. As such, NAFs are much more difficult to clean.
Although spacers are intended to separate drilling fluid from cement, a small amount of spacer fluid—from 5% to 10%—typically contaminates a portion of the cement slurry. Many spacer chemistries affect cement properties, such as thickening time, rheology, and compressive strength, often precisely where zonal isolation is most essential.
If the cement has not fully hardened by the time a cement bond log is run, it may not show up clearly and the top of cement (TOC) may be uncertain. Therefore, it is vital to ensure that spacers remove the maximum amount of mud while having a minimal effect on cement properties.
Since NAF compositions vary widely, there are no universal spacer formulations. Most are designed and tested on a case-by-case basis using procedures that differ from one operator or location to another. Existing American Petroleum Institute (API) recommended tests for evaluating the suitability of a particular spacer have been found nonrepeatable.
In addition, no test protocols exist for well conditions above 85°C, despite the large number of cement jobs in wells with bottomhole temperatures of up to 150°C. Along with salinity and the type of drilling fluid, temperature is one of the most critical factors influencing cement integrity. Thus, enhanced test procedures and spacer formulations are needed.
The Shale Evolution: Zipper Fracture Takes Hold
Authors: Jacobs Trent 
Published: February 2015

Zipper Fractures
A horizontal well completion method known as zipper fracturing has been rapidly adopted over the last couple of years by companies in the Eagle Ford shale of south Texas. Instead of drilling and hydraulically fracturing one well at a time, the zipper method involves drilling multiple wells from a pad site and then hydraulically fracturing a stage in one well, while getting ready for the next, as wireline and perforation operations take place in another. The multiwell completion method earns its name from the zipper-like configuration of the fracture stages from wells drilled with relatively tight spacing.
This shaves days off the time it takes to complete a multiwell pad. Many companies in south Texas are now using the completion method on almost every new pad site they drill into, saving tens of millions of dollars per year while accelerating the development of their well inventories.
But the big prize may be that zipper fractures are increasing initial production and estimated ultimate recovery rates when designed so that the fractures stimulate the most reservoir volume possible. Tulsa-based WPX Energy, an independent operator of 160,000 acres in the San Juan Basin of New Mexico, told investors this summer that when the company switched to zipper fracturing, it averaged 420 B/D of oil production compared with 388 B/D from single-well completions. While not entirely sure if zipper fracturing is the direct cause of improved production, WPX said it expects that is the case.
Mukul Sharma, a professor and chair in the petroleum department at the University of Texas at Austin (UT), said field data from Eagle Ford wells make it clear to him that zipper fractures are indeed improving initial production rates and the estimated ultimate recovery. Sharma said operators in south Texas have reported improved initial production rates ranging from 20% to 40% using the zipper method. “I would say that this is definitely the way people are going to be doing a lot of their fractures in the future,” he said. “What I think we need to do is understand better how it works— why it works. Once we understand that, we can apply it much more efficiently.”
Legends of Artificial Lift
Authors: Noonan Shauna , Beckwith Robin 
Published: February 2015

Meet the Legends
Artificial lift is a critical technology used to keep wells producing when they are incapable of providing enough energy—in the form of pressure—to produce liquids to surface at economic rates. Most development plays throughout the world would be uneconomic without artificial lift. JPT Features Editor Joel Parshall, in his March 2013 JPT article titled, “Challenges, Opportunities Abound for Artificial Lift,” writes There is no global repository of artificial lift statistics; however, industry observers estimate that 90% to 95% of the world’s producing wells currently use artificial lift, said Bill Lane, vice president of artificial lift systems emerging technologies at Weatherford. “It is trending more toward 95% than 90%, and probably 100% of producing wells would use artificial lift at some point in their lives, except for wells shut in prematurely because of economic factors.”
The 2014 SPE Artificial Lift Conference and Exhibition for North America, held in Houston 6–8 October, features a special Legends in Artificial Lift Luncheon on its final day. At the luncheon, five people who have dedicated their careers to artificial lift (AL) will be honored for their outstanding contributions to the field of AL technology. The SPE Legends of Artificial Lift Award recipients are Herald Warren Winkler, James F. Lea Jr., Maurice Patterson, Sam Gavin Gibbs, and Joe Dunn Clegg. Serving on the SPE Board as 2014 SPE Technical Director for Production and Operations, I am proud to host the ceremony along with 2014 SPE President Jeff Spath, who will give an address and present the special recognition awards to the five men whose lifework distinguishes them as AL legends.
Each honoree is being recognized for accomplishments in a specific type of artificial lift—or as a champion of all AL techniques. These individuals’ curiosity, keen observation, and dedication to physical truths have, time and time again, trumped conventional wisdom, revealed ineffective techniques and exaggerated product claims, and led to forward-looking insights that have until this day driven many AL advancements in understanding, technology, and techniques. For many production engineers—including me—these five modest men are influential mentors whose work has played a major role in making the AL industry such an exciting and rewarding field to work in. JPT