bluuebunny/crossref_metadata_2025 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
Pumping Oil: 155 Years of Artificial Lift
Authors: Beckwith Robin
Published: February 2015

History of Artificial Lift

On 27 August 1859, near Titusville, Pennsylvania, USA, “Colonel” Edwin Laurentine Drake found “rock oil” in a well he deliberately drilled to produce it.

It was not just the oil that ushered in the modern petroleum era, but also the rig and tools Drake and his driller, saltwater-well expert and blacksmith “Uncle Billy” Smith, used to drill and pump the oil from the well.

“[T]he production end of the fledgling oil industry was able to launch its phenomenal expansion,” writes hydraulic pumping pioneer Clarence J. Coberly in “Production Equipment” (History of Petroleum Engineering, American Petroleum Institute, 1961), “with the almost-identical tools and techniques that had been developed in the waterwell industry.”

The greatest influence on the initial production equipment used by the oil industry, writes Coberly, resulted from the cable tools used to drill the wells: “The oscillating walking beam—a simple and effective means of lifting and dropping the bit—was also well-suited for operating the bottomhole plunger pump once the well was completed. Both drilling and pumping loads were small enough to permit the use of wooden structural elements with a few pieces of iron to serve as bearing points. As crude as the rig was, it was effective and inexpensive.”

Coberly also notes that almost all advances in drilling and producing methods relied either directly or indirectly on the use of casing. The first cased well was likely in 1861.

Within 10 years of Drake’s discovery, well casing was routine and conventional pumping equipment was well-established as consisting of what is now known as the “standard rig front.”

History: Sucker-Rod Lift (Beam Pumping)

Pumping by combining a walking beam and sucker rods extends back at least to 476 CE, when the walking-beam principle was known to have been used in Egypt. In addition, archeologists—when excavating wealthier families’ homes that existed in the early days of the Roman Empire—have found double-acting pumps, made of cast lead, with plungers made of wood and leather. Roman sucker rods were made of wood and worked in compression.
Industry Challenges Drive the Need for New Business Models
Authors: Schorn Patrick
Published: February 2015

Management

The increasing diversity of oil and gas resources presents technical challenges for our customers—and at the same time opportunities for oilfield services companies. The challenges range from reducing subsurface risk as exploration and appraisal begins, to increasing the ultimate recovery achievable when the reservoir reaches the end of its economic life. These challenges can be impacted by technology, workflow, people, global back-office support, software, and by business models, which are evolving as the demand for integrated operations has increased over the years.

Business Models Evolution

In terms of business models, the integration of products and services with workflow and process can take many forms. Fig. 1 shows the evolution of business models for our industry. As the pace and complexity of operations have grown, the traditional approach—typically known as “discrete” services—has become increasingly inefficient and expensive for our customers to manage. To control costs and minimize downtime, operators may solicit tenders for “bundled” services, lumping together several related discrete offerings from a single supplier for a lower total cost. While this “bundled” approach may reduce the price, it often fails to boost efficiency, especially when the entire product lines and in many cases, the individual service provider, continue to function independently.

Given these drawbacks and the magnitude of the challenges facing the industry today, both onshore and offshore, what we need are truly integrated operations. So you might be wondering: What is an “integrated” operation? Put simply, it is one in which the interactions among the parts are fundamentally different than they have been in conventional discrete or bundled services operations. In integrated operations, all the products, services, and personnel are streamlined and coordinated across the usual domain boundaries as if they were a cohesive system with a single objective.

As an industry, we need to integrate services in field operations, at the well site, as well as technologies and engineering workflows back in the office. The ultimate integrated operation would be one in which both parties—oil company and service provider—work together as one, removing the duplication of efforts that is currently taking place.

Our Integrated Project Management business is one example of this. It is made up of well construction and production management projects and we have a large organization that supports these types of projects. It was started 19 years ago to address a growing requirement to integrate services and technologies and has grown into a portfolio of multiyear, multirig contracts as well as into technically more challenging work in deeper and tougher wells. The majority of the contracts are long term. The evolution of these business models has changed from the mid-2000s to year-end 2013, with a trend toward integrated-type projects.
Soft Competency Development as a Global Challenge
Authors: Fattahi Behrooz , Milanovich N. , Howes Susan , Paccaloni Giovanni , Brett Ford
Published: February 2015

Talent & Technology

The global nature of the workplace in the petroleum industry has introduced a new challenge to our competitive business landscape: the development of soft competencies as a critically important element in driving productivity. Soft skills as an element of sustainability brings success to individuals and organizations in a variety of workplace activities, such as forging alliances, creating a team harmony that produces collaboration and innovation, and managing and using the human and system components to influence outcomes and achieve business goals. As the nature of workplace engagement shifts, soft competencies provide individuals with the ability to manage the social, cultural, technical, and environmental expectations of both the individuals and their organizations.

In an October 2013 JPT article, the Soft Skills Committee of SPE introduced the Soft Competency Matrix, which is governed by attributes stemming from progression in people capabilities and actions; growth and augmentation of human capabilities with age and experience; and socioeconomic, cultural, and traditional dimensions (Figs. 1 and 2). The authors noted that while the first two elements were governed by a continuing journey through time and personal maturity dimensions, the changes in the third element could be abrupt depending on the attributes needed for the new work assignment.

Global Challenge for SPE

The use of the matrix allows individuals to measure their soft competency level against the expectation to identify current gaps and chart an improvement path. This is obviously a starting point for engagement to better manage and prepare for the ongoing changes and to save time to autonomy for our industry professionals. Moving from a world primarily defined by the location business needs and technical capabilities to one that also emphasizes soft competency as a requirement for success allows the employers to assess the competency gaps in their employees’ soft skills.
Achieving Drilling-Performance Improvement in Horizontal Tight-Gasfield Development
Authors: Wilson Adam
Published: February 2015

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 166699, ’Achieving Drilling-Performance Improvement in Horizontal Tight-Gasfield Development,’ by Mohamed Najwani, SPE, Yaseen Najwani, SPE, and Hani Al Lawati, BP Exploration (Epsilon); Colin Cockburn, SPE, BP Exploration Operating Company; and Mohammad Reza Heidari, SPE, and Martin Sanderson, SPE, Schlumberger, prepared for the 2013 SPE/IADC Middle East Drilling Technology Conference and Exhibition, Dubai, 7-9 October. The paper has not been peer reviewed.

The full-field development plan for the Khazzan project in Oman is based on drilling approximately 300 wells targeting gas-producing horizons at measured depths of approximately 6000 m with 1000-m horizontal sections. The first attempt to drill these wells had to overcome many drilling challenges, including wellbore instability and drilling dysfunctions. This paper shows how the application of existing technologies and processes is leading to performance gains and improvements in wellbore quality.

Introduction

BP has embarked on an appraisal drilling campaign that targets a tight gas reservoir in northern Oman. The subject field is an area of approximately 2800 km2 and contains the Cambrian Barik, Miqrat, and Amin reservoirs.

The field-development plan is based on a deep-horizontal-well design. When the appraisal phase began, there was very limited experience within the country in drilling deep horizontal gas wells. Other operators in Oman were mostly drilling vertical gas wells. There were no analog data available on horizontal wells in the Barik reservoir.

The wells will be drilled vertically to approximately 4000-m measured depth before building up and landing to horizontal in the Barik or Amin reservoir. An 8½×8?-in. 1000-m horizontal interval is drilled, and a 7×4½-in. tapered liner is cemented in place before fracturing operations. Figs. 1 and 2 are schematics of the well designs.

The targeted reservoir is either Barik or Amin sandstone, both of which have a high unconfined compressive strength (exceeding 35,000 psi). The Barik sandstone is at the upper margins of the global rock-strength envelope. Indeed, when core samples were analyzed by the bit manufacturer, the strength far exceeded any of their global stock of reference rock samples.

Horizontal drilling in these hard-rock conditions presents several challenges:

Hard rock and slow rate of penetration (ROP)

High levels of shock and vibration

Polycrystalline-diamond-compact (PDC) -bit cutter durability

Drillpipe fatigue

Wellbore stability

Torque and drag management

High downhole static temperatures up to 143°C
Technology Focus: Sand Management and Sand Control (October 2014)
Authors: Wetzel R.J.
Published: February 2015

Technology Focus

In recent years, I have not seen any significant changes in the systems used for sand control, and I have been wondering why. It may have more to do with our confidence and comfort in our current approaches than with not having any Earth- shattering new ideas. The phrase “necessity is the mother of invention” is probably valid in this case.

The necessity has been evident in the ways that our industry has expanded the capabilities of the existing systems that we already use successfully. These expansions are in a great many areas—temperature, pressure, size, length, materials used, modeling capabilities, reliability, complexity, and more.

I think it is safe to say that the engineers and companies involved, in either building or using sand-control systems, have made significant strides and have added critical learnings to our industry. I expect that we will have another revolution or revelation in sand management or sand control. As an example, development of unconventional and tight-rock assets is causing our industry to develop novel approaches to the tools and the pumping processes that are used. I am already seeing some of those ideas showing up in the modifications to our proven sand-control systems.

In line with this broader scope of sand-control systems and methods, this feature, previously called Sand Management and Frac Pack, is being renamed. The new name is Sand Management and Sand Control. This new name recognizes that there is a range of systems and approaches that continue to be used by our industry as we work to provide the best approach for each asset that we develop. I am confident that you, our readers, will agree with this broader scope.

The papers selected for this feature focus on some remarkable adaptations based on standard systems and problems that we have faced for years. These papers highlight multizone applications, erosion tolerance, and shale stability and control. All of these are dealt with every day, in various ways, by completion engineers around the world. JPT

Recommended additional reading at OnePetro: www.onepetro.org.

OTC 24884 Single-Trip Multizone Gravel-Packing Case History Improves Anticipated Production From the Berantai Field by E. Damasena, Petrofac Energy Development, et al.

SPE 169440 Design and Validation of an Improved Shunt-Tube System by A. Bonner, Halliburton, et al.

SPE 168636 Evolution of Frac-Pack Design and Completion Procedures for High-Permeability Gas Wells in Subsea Service by Vibhas J. Pandey, ConocoPhillips, et al.
Energy's Struggle with Rapidly Changing Roles, Responsibilities, and Reputation
Authors: Mathieson Derek , Bryant Peter J.
Published: February 2015

Guest editorial

Almost every aspect of modern society is supported or influenced by energy—and yet it is one of the least understood and possibly one of the most reviled industries on the planet. Whether we like it or not, the energy sector’s public image has been shaped over the past couple of generations to be synonymous with corporate profiteering, environmental disregard, and social abstinence. It is hard for those of us who work in this industry to rationalize such a reputation when we know that our collective programs on safety, the environment, corporate social responsibility, and technology innovation are among the best to be found in any sector.

This is the energy paradox, and in the face of an ever-growing and daunting demand for energy, it is apparent that the industry’s relationship with society has to change. But is it one that we can tackle on our own?

Changes at Scale

Nowhere is the energy paradox more evident than with the shale revolution in the United States. In just a few years, the industry has moved from initial experimentation to drilling almost 40,000 wells per year—changing employment and prosperity in many parts of the country, creating the potential for energy independence, and disrupting long-standing equilibria in the geopolitical landscape. In addition to this direct impact, the promise of sustained, accessible, and affordable energy is becoming a powerful economic multiplier, with an increasing number of new manufacturing plants replacing coal with natural gas, resulting in a marked impact on the reduction of carbon emissions.

The sheer scale of this activity, though, is stressing domestic infrastructure beyond design, overloading pipelines, roadways, and rail networks. More and more, these activities are expanding into private land and creating new engagements among companies that represent our industry and stakeholders in communities, local governments, and states. It remains to be seen to what degree these constituents are willing to deal with what is, in effect, the reindustrialization of the United States when it is in their own backyards.

Energy as a Foreign Language

We do have some strong indications that people are taking notice. Shale development today dominates the conversations and activities of a myriad of special interest groups, trade organizations, and government and community initiatives as well as industry forums. However, with more than 10,000 E&P companies working in this space in the United States alone, all of these activities, while important in their own right, are extremely fragmented and very few represent more than a few stakeholders.

It is at the interfaces among all these groups that the energy paradox is most obvious. The industry, mostly well intentioned, has typically developed messages that are too often meant to “teach” other groups about the “facts” of shale development. But these messages can be perceived as arrogant, condescending, and uncaring by stakeholders who have other, just as well-intentioned, viewpoints.
E&P Notes (November 2014)
Authors: Jacobs Trent , Rassenfoss Stephen
Published: February 2015

E&P Notes

Testing the World’s First Modular Capture Vessels

Trent Jacobs, JPT Technology Writer

In response to the 2010 Deepwater Horizon incident that claimed the lives of 11 men and led to the worst oil spill in United States history, the offshore industry devised new technologies and methods that would allow for a quicker response if a similar event was to occur again in the US Gulf of Mexico. Among the newest response systems are the conversion of two Aframax lightering tankers into capture and containment systems capable of handling 100,000 BOPD of oil and 200 MMscf/D of gas. The company that designed the emergency-response vessels said they are the first production facilities to be built with the hope of never seeing first oil.

“They are basically (floating production, storage, and offloading units) that are now available in the Gulf of Mexico for this application,” said Charles Miller, chief technology officer of Marine Well Containment Company (MWCC) at the recent SPE Deepwater Drilling and Completions Conference in Galveston, Texas.

Saudi Aramco Displays Reservoir Research Priorities

Stephen Rassenfoss, JPT Emerging Technology Senior Editor

Saudi Aramco’s plan to create a global network of research centers is becoming a reality. It recently celebrated the opening of its Houston center that the company’s President and Chief Executive Officer Khalid Al-Falih described as “an upstream research center like no other.”

The opening of the Aramco Research Center in the heart of the energy technology center in Houston offered a look at how the national oil company is bringing in expertise from around the world to bear on maximizing output from Saudi Arabian reservoirs. The new research center is an extension of Saudi Aramco’s research hub in Dhahran, with complementary groups working on reservoir monitoring and imaging, as well as sensors and drilling. But there is something unique in the Houston center: unconventional reservoir research and development.
Stakeholder Issues Play Key Role in Shale Future
Authors: Parshall Joel
Published: February 2015

Stakeholder Engagement

As the shale revolution changes the map of oil and natural gas development and shifts the balance of production between regions, public acceptance is an increasing challenge. The unconventional resource boom has brought intensive drilling and production operations to areas often unaccustomed to these activities and frequently more populous than traditional petroleum development areas.

A variety of public concerns have assumed a high profile, including the environmental issues of water use; perceived risk to groundwater aquifers; waste disposal; truck traffic, dust, and noise; and emissions.

While the success of production from shales and other tight-rock formations draws attention nationally and globally, its future depends much on the attention and reception it receives locally. As shale drilling has surged, public eyes may be more focused on the community impacts of oil and gas operations than ever before.

Some jurisdictions have imposed moratoria or even bans on the use of hydraulic fracturing, which is an essential component of the success of shale development. The risk of similar measures and additional restrictions spreading to other areas is real. There is increasing industry recognition of the need to reach out to communities, share information, and listen to stakeholders.

Enactments such as fracturing moratoria and bans are “the single thing that can stymie more development in these unconventional resource plays,” said Clay Bretches, chief executive officer of Sendero Midstream. Formerly vice president of E&P services and minerals at Anadarko, Bretches chaired the coordinating subcommittee of the North American Resource Development Study for the National Petroleum Council’s (NPC’s) report, “Prudent Development— Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources,” presented to the United States Secretary of Energy in September 2011.

For the industry, Bretches and others said, sustainable success in field development demands an increased willingness and ability to engage all stakeholders, including communities and local governments, nongovernmental organizations (NGOs), and a variety of industry-related bodies. This is in addition to higher levels of government that are customarily involved. The need for increased stakeholder engagement was emphasized in the “Prudent Development” report.
Ultra-HP/HT Drilling-Fluid Design for Frontier Deep Gas Exploration
Authors: Wilson Adam
Published: February 2015

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper OTC 24830, ’Ultra-HP/HT Drilling-Fluid Design for Frontier Deep Gas Exploration in South Malay Basin,’ by Anuradee Witthayapanyanon, SPE, Kathi Chandramouleeswaran, Ahmad Bin Dollah, SPE, Dennis Clapper, SPE, Ronald Bland, SPE, and Akachai Kongsawast, SPE, Baker Hughes; and Michael Pepple, SPE, Khairul Anwar Nasrudin, SPE, and M. Abshar, SPE, Petronas, prepared for the 2014 Offshore Technology Conference Asia, Kuala Lumpur, 25-28 March. The paper has not been peer reviewed.

This paper discusses the laboratory evaluation of potential high-pressure/high-temperature (HP/HT) drilling-fluid designs considered for a deep gas exploration well in Malaysia. Laboratory testing included evaluation of rheological properties, fluid loss, sag, and electrical stability, along with chemical analysis. Properties were measured before and after extended dynamic and static aging, up to the expected bottomhole temperature (BHT) and bottomhole pressure. Formulations were adjusted and retested until acceptable results were achieved.

Introduction

Proper drilling fluid is a critical component in safe drilling in HP/HT exploration. High subsurface pressures are controlled by the elevated density of the drilling fluid achieved through high concentrations of weighting agents. However, high-density muds often possess high rheological properties and, as a result, exhibit high equivalent circulating densities (ECDs), lost circulation, and low rates of penetration. Formulating thermally stable fluid for extreme high temperatures is a challenging task because conventional oilbased- mud additives thermally degrade at approximately 400°F. Nevertheless, maintaining constant fluid density in extreme borehole conditions is essential for well control.

Well Background and Drilling Objectives.

The well was one of the first ultra- HP/HT exploratory wells planned for the South Malay basin. The objectives of the drilling-fluid design for this well were

No nonproductive time associated with drilling mud

Stable drilling fluid with low shear strength at static BHT (SBHT) for 16 and 48 hours

Stable rheological properties at SBHT

No excessive ECD associated with drilling fluid at bottomhole circulating temperature

Controlled HP/HT fluid loss as per program and wellbore conditions

Controlled salinity of water phase to balance formation

Drilling-Fluid Design for Ultra-HP/HT Deep Gas Well

The surface and upper-hole-section drilling- fluid plan for this well mainly consisted of high-viscosity sweeps of saltwater gel and potassium chloride water- based mud. Invert-emulsion drilling muds were used in the lower sections of the well.