bluuebunny/crossref_metadata_2025_split huggingface dataset:
Cross-Industry Hydrocarbon-Release Analysis
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 145449, ’Cross-Industry Hydrocarbon-Release Analysis,’ by Amy Li, Oil & Gas UK, prepared for the 2011 SPE Offshore Europe Oil and Gas Conference and Exhibition, Aberdeen, 6-8 September. The paper has not been peer reviewed.
An analysis was made of hydrocarbon releases (HCRs) occurring on the UK continental shelf (UKCS) during the period of 2008 through October 2010. The analysis included the type of hydrocarbon released, operating mode during which a release occurred, release site, age of installation, type of installation [manned or unmanned; floating production, storage, and offloading vessel (FPSO); floating production facility (FPF); or fixed installation], and the underlying cause of the release. This study aimed to assist the industry in identifying where it can best place its resources to reduce the number of HCRs.
Introduction
HCRs are potential precursors to major accidents, with the 2010 Gulf of Mexico incident being a tragic reminder of that potential. Also, the number of HCRs is a performance indicator of asset-integrity management of the offshore installations. Since the creation of Step Change in Safety (UK offshore-safety initiative) in 1997, there has been a 52% reduction in major and significant HCRs. Industry-wide workshops, sharing of best practices on asset integrity, and development and use of toolkits and guidance documents led to an early period of sustained year-on-year reductions in the number of major and significant HCRs. In spite of sustained efforts in recent years, progress appears to have stalled. The total number of HCRs per year has fluctuated between 155 and 190 in the past 5 years, while major and significant HCRs have remained in the range of 60 to 85 per year during the past 7 years. The offshore oil and gas industry is not complacent, and at the end of 2010, Step Change in Safety published a revised HCR-reduction target. The UK offshore oil and gas industry, as a whole, agreed on a target of 50% reduction of HCRs by the end of March 2013 vs. the 2009–10 total HCRs of 187. The challenge for the UK offshore industry is to decide where to focus its effort to reduce the number of HCRs and to achieve its revised target.
Data Sources
Most of the information was extracted from the HCR root-cause-analysis exercise conducted by the Step Change in Safety Asset Integrity Steering Group at the end of 2010. Twenty duty holders supplied their HCR information for the period of 2008 through October 2010. Information on 474 HCRs was collected, and some duty holders also submitted information on leaks that were below the reportable criteria.
SPE Distinguished Lecturer Program 2012-13
Authors: JPT staff _ 
Published: February 2015

Program review
Featuring 28 speakers from various disciplines and professions, the 2012–13 Distinguished Lecturer Program emphasizes current industry trends, challenges, and technology through diverse topics. Subject areas and speakers featured in this year’s program are listed here.
Advancement in Sand Control Fluid Technology
The number of reservoirs requiring sand control is growing at a fast pace. Fluids play an important role in successful design, execution, and performance of sand control completions. This presentation will familiarize the audience with key fluid technologies, examine benefits and limitations, review development processes, demonstrate success with the aid of case histories, and identify technology gaps.
Bala Gadiyar is a principal engineer at Schlumberger in Houston. He holds a BS degree from the University of Pune and MS and PhD degrees from the University of Oklahoma, all in petroleum engineering.
Improved Recovery and Reduced Costs With Intelligent Interventions—Make Your Wells Intervention Friendly
This presentation will offer an operational perspective on the state of light intervention technology available in the industry and how it is changing the way some operators design their wells for intelligent interventions by making them more intervention friendly. It will also discuss the merits of integrating more contingency planning into subsea, intelligent, and unconventional wells based on light well intervention experience within the industry.
Brian Schwanitz is a graduate of Michigan Technological University in applied geophysics and has worked in the oilfield service industry for the past 34 years.
Crosswell Seismic: Imaging and Monitoring of the Reservoir
This talk highlights the resolution benefit of crosswell seismic, including recent technology enhancements in crosswell imaging that make the method suitable in real-world reservoirs and a number of examples from a variety of applications where crosswell seismic adds economic value in reservoir development, both in high-resolution reservoir characterization and reservoir monitoring
Bruce Marion is general manager of DeepLook-CS, Schlumberger, in Houston. He has been involved in crosswell seismic technology and operations for more than a decade.
Innovation: Volunteerism in SPE
Authors: Imomoh Egbert 
Published: February 2015

President's column
This is the last column I will write before the end of my tenure, and I could not think of a better subject to discuss than volunteerism in our global society. As I visited sections and student chapters in different parts of the world, I have been amazed at the number of our members who give valuable time and talent for the good and growth of SPE. I have also been more acute in my observation of volunteerism in our daily lives. For example, early one morning I noticed an elderly lady at a pedestrian crossing helping young children cross a busy road on their way to school. Instead of being cuddled in bed, she was giving her time selflessly to her community.
There are of course many heroic examples, but in most cases volunteers do not go that far. Typically, volunteers give part of themselves for the good and growth of the group they belong to.
The issue of volunteerism was brought to sharp focus when I had the pleasure of a 7-hour drive with a regional director whilst traveling between sections. Our discussion was about why people volunteer. We spent quite some time discussing what drives people to give up their valuable time for activities that don’t result in overt rewards. I have routinely asked members, “Why do you volunteer?”
As to be expected, the responses are varied. Some have joined this corps of volunteers because someone invited them to do so; others have done so to be able to give back some of the benefits they derived from the work of other volunteers; some see the need to ensure that future leaders are exposed to the vast knowledge that SPE has gathered over the years; and others were grateful for the social interaction across the various strata of SPE members and the opportunities to occupy a leadership role out-side their work environment. Whatever the reasons are, the fact remains that a sacrifice has to be made, ranging from adding extra-long hours in the work day to giving up time with family in order to carve out time for SPE activities.
New Methods Developed to Manage Subsea Vibration-Induced Fatigue
Authors: Swindell Rob 
Published: February 2015

Technology Update
The vibration assessment of subsea systems has largely been limited to vortex-induced vibration of riser systems and unsupported pipeline spans (i.e., environmental loading) caused by flow past the outside of a riser or conductor. But now, piping vibration caused by process excitation is becoming an issue on manifolds and jumpers, in part associated with increasing production rates. Though the likelihood of a failure is low, the consequences can be high, resulting in an unacceptable level of risk. As well as piping integrity issues, additional vibration-related problems have also been experienced with valves and instrumentation.
Process Excitation Mechanisms
There are a number of different sources of excitation and these generally depend on the type of process fluid within the system. The following three mechanisms are the most common.
Flow-Induced Turbulence. This is caused by broad band, low-frequency energy, generated by “single phase” turbulent flow through valves, expansions and bends—essentially anything that disturbs the flow. This can lead to excitation of the low-frequency modes of the piping system by energy transfer from fluid momentum to the pipe, resulting in low-frequency vibration (up to possibly 50 Hz). This is widespread in most processes and depends heavily on the velocity and density of the fluid.
Multiphase Flow. This encompasses slug, bubble, annular, and churn flow. The frequency range of the resulting excitation is heavily dependent on void fraction and flow regime.
Flow-Induced Pulsation. This is linked to gas flow through a flexible riser or jumper, sometimes known as the “singing riser.” This is where gas across the internal corrugated geometry within the flexible piping causes vortex generation. This can cause a pressure fluctuation, or pulsation, with a frequency and amplitude that are dependent on the gas velocity. This pulsation can drive the flexible piping at either end at very high frequencies—in some situations as high as 1,000 Hz—causing fatigue damage to accrue very quickly. The phenomenon is typically only experienced on dry gas systems, so it can be an issue on gas export, gas injection, and gas lift systems.
The Hidden Threat
Pipe design and construction can present a number of unique challenges in subsea developments, given their remoteness and complexity to access. A vibration issue may occur subsea without any obvious sign topsides.
Finding Pathways to Produce Heavy Oil From Canadian Carbonates
Authors: Rassenfoss Stephen 
Published: February 2015

Alberta Heavy Oil
Nearly 2 million bbl of ultraheavy crude are produced each day from Canadian oil sands, but the notion of also producing bitumen from reservoirs made of carbonate rock can spark skeptical remarks.
They are likely to say something like: “Carbonates are very different. In carbonates, it is just different,” said Daniel Yang, director of reservoir engineering at Laricina Energy, who has a different reading of the exploration history of formations that hold more than 400 billion bbl of the crude.
Laricina has partnered with a second Calgary independent, Osum Oil Sands, to try to prove that bitumen can be commercially produced from the Grosmont formation, which holds 75% of the heavy crude known as bitumen in Alberta’s carbonates.
The reality is the Grosmont is different. A pilot project by Laricina and Osum showed that the well design commonly used for oil sands is not a good fit in carbonates. But a mix of methods used for bitumen production worked well enough to convince the partners to plan a commercial test. that they plan to use for the first commercial development in the formation.
The Laricina-Osum joint venture has filed for a permit to produce as much as 10,700 B/D from up to 32 wells, with first oil in 2015. Husky and Shell have also filed for permission to do pilot projects with the Alberta Energy Regulator, the agency formerly known as the Energy Resources Conservation Board (ERCB).
“It is going like early development in major oil sands basins such as the Athabasca, where there were many field pilots,” said Eddy Isaacs, chief executive officer of Energy and Environment Solutions at Alberta Innovates, a provincial agency that funds research, including past carbonates work.
But moving from wells producing oil in situ in the relatively consistent sandstones and unconsolidated sands to carbonates will require significant advances in production methods and simulation software. The Grosmont was born complicated. It was formed hundreds of millions of years ago from the hap-hazard deposition of marine life off a long shoreline, was chemically transformed into dolomite, followed by water flows that carved it up, widening the fractures and carving out so many holes in the rock that it created weak spots in a formation that has been lifted and crushed and filled with oil that degraded into some of the world’s heaviest crude.
New Challenges Demand New Energy Leadership Skills
Authors: Lloyd Frank 
Published: February 2015

Talent & Technology
New technologies have enabled the energy industry to access a bounty of oil and gas so large that worries about running out have melted away. Some journalists have even turned their attention from “peak oil” to “peak car,” as the number of miles driven by many urban dwellers declines and as teenagers who prefer to connect using social media delay the age at which they acquire driver’s licenses. “Suddenly, out of nowhere, the world seems to be awash in hydrocarbons,” said Michael Greenstone, an environmental economics professor at the Massachusetts Institute of Technology. And yet, abundant and growing supplies that can easily meet the world’s energy demands have not eliminated the industry’s complexities and challenges. Three new challenges that demand new leadership skills stand out.
Consolidation. According to financial analysts, the financial markets understate the value of many energy company stocks, paving the way for continued consolidation that will require more sophisticated levels of financial and organizational leadership. Yet firms are reluctant to take new risks and invest in human capital to develop a higher level of leadership when they may be acquiring or acquired in the foreseeable future.
Changing Roles. The service sector is gaining increased importance within the industry. Service firms represent the bulk of research and development spending, more than twice what exploration and production (E&P) firms now spend. They are increasingly taking risk positions in oilfield drilling and development. This provides E&P firms opportunities to outsource technical development. In addition, supermajors are outsourcing E&P operations to mid-majors and buying back the rights to develop newfound plays. Service firms also represent the bulk of industry hiring, adding jobs at three times the rate of E&P firms. And they are forming direct relationships with national oil companies. All this means that leaders in service sector and mid-major firms are being forced to increase their ability to assess risk, form alliances, and navigate the global industry.
Design-Guideline Strategies for High-Pressure/High-Temperature Equipment
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 23943, ’Design-Guideline Strategies for High-Pressure/High-Temperature Equipment,’ by H. Brian Skeels, Kwok Lun Lee, and Anand Venkatesh, FMC Technologies, prepared for the 2013 Offshore Technology Conference, Houston, 6-9 May. The paper has not been peer reviewed.
As the need for oil and gas equipment working in hotter and higher-pressure environments continues to mount, the effort to develop an adequate set of design, material, and validation practices continues to be challenging. More-rigorous stress analysis and design methods that more closely model fast-fracture burst conditions are needed to achieve safe, reliable, and cost-effective equipment designs.
Introduction
As oilfield equipment is subjected to more-severe and longer periods of cyclic forces (internally from irregular wellbore flowing conditions or externally from metocean conditions), many agree that fatigue life and monitoring for these conditions has to be a part of the design equation. This fact is mentioned in the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code, recognizing the two failure modes of a pressure vessel: leak before burst or a fast-fracture burst. Many oilfield design guidelines negated a need for fatigue analysis because of the long-standing practice of keeping maximum design loads and stresses well below two-thirds material yield strength, a practice that also keeps cyclic-loading issues well inside the “infinite” region on S/N curves in most cases. Unfortunately, this quasi-static design philosophy grows less accurate as the pressure vessel’s wall thicknesses grow or geometries become more complex when addressing high-pressure/high-temperature (HP/HT) conditions. As a result, many have turned to the ASME Boiler and Pressure Vessel Code for guidance. Divisions 2 and 3 of the ASME Code present alternative design methodologies to be considered as internal pressure and temperature increase. However, the designer, using the code, is still free to select which division to follow for his application.
The American Petroleum Institute (API) has long followed a subset of Division 2 of the ASME Code, but it now recognizes many shortcomings as one considers HP/HT conditions. The published technical report only cites the current state of the art and discusses the issues to be tackled. Many observers agree that leaving the issue to so-called “sound engineering judgment” would result in many variations of opinion between operators and manufacturers, likely resulting in inefficiency and repeated tasks. Current efforts address two options: extending current API design practices to higher pressure ratings or establishing a demarcation when different design practices are needed.
HP/HT Pipelines Designed for Lateral Buckling in the South China Sea
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 17181, ’HP/HT Pipelines Designed for Lateral Buckling in the South China Sea,’ by H. Brian Skeels, Kwok Lun Lee, and Anand Venkatesh, FMC Technologies, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed.
Gas production in the South China Sea has seen an increasing trend of pipelines operating in high-pressure, high-temperature (HP/HT) conditions. This has led operators to look beyond the conventional stress-based design and move into strain-based design using the lateral-buckling-design approach. This paper presents both construction challenges and operational works post-startup, aiming to provide operators with cost-effective construction solutions and a risk-based maintenance philosophy when considering lateral-buckling design.
Introduction
Lateral-buckling design is a strain-based design that allows the pipeline to expand laterally at locations in a controlled manner. This allows the pipeline to relieve its thermal expansion by lateral movement rather than being axially restrained (i.e., through trenching and burial).
As with any unconventional methodology, such design has certain limit states that require careful consideration. These limit states include local buckling, low cycle fatigue, fracture, and pipeline walking. These limit states are addressed during the design phase, except for fracture, which is addressed during the construction phase. During operation, these limit states are also monitored periodically to ensure that design thresholds are not exceeded.
Construction Challenges and Solutions
Initiation Method. Lateral-buckling design requires suitable initiation methods to ensure that the planned lateral buckles for a pipeline are initiated at the designated locations during startup. The initiation methods are typically executed during the pipeline installation itself rather than before or after the installation. It is therefore important that the initiation method be as practicable as possible for construction, and also effective, to guarantee the success of the lateral-buckling design.
The purpose of an initiation method is to provide a low critical buckling force at the designated location, thus providing a higher probability that the planned buckle will initiate at the location intended. This can be achieved by creating an artificial imperfection either vertically or laterally on the seabed. One of the most frequently used methods, which combines both vertical and lateral imperfections, is the zero-radius-bend (ZRB) with buckle-trigger method.
Extensive Environmental-Monitoring Project Relies on Integration of Several Networks
Authors: Wilson Adam 
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 156294, ’Innovative Environmental Monitoring for Upstream Onshore Installation,’ by Paolo Carnevale, SPE, and Silvia Di Croce, Eni, prepared for the 2012 SPE/APPEA International Conference on Health, Safety, and Environment in Oil and Gas Exploration and Production, Perth, Australia, 11-13 September. The paper has not been peer reviewed.
A comprehensive environmental-monitoring project in the Agri Valley in southern Italy has been developed to ensure continuous management of the environmental effects of Eni’s oil treatment center there. This project is able to control the environmental effects of exploration and production in a large area around the plant (100 km2). It is characterized by a complete integration of several networks, stations, and systems used to monitor simultaneously air quality, noise, odorous emissions in terms of olfactory nuisance, groundwater and soil quality, ecosystems status, and ecological biodiversity.
Introduction
The area where the environmental-monitoring project was developed is characterized by sites that have community-level protection, especially areas protected because of national parks, widespread woods, rivers and streams of high quality, and springs and ground water of great regional and national importance for the production of safe drinking water.
Eni’s oil treatment center in this territory collects the production from 24 oil wells, amounting to approximately 104,000 BOPD (Fig. 1).
The environmental-monitoring plan consists of environmental-monitoring networks on more than 100 km2 at altitudes between 600 and 900 m. The system includes monitoring networks relevant to the following environmental variables:
Air quality
Biosystems
Bad odors
Noise
Microseismicity
Ecosystem
Air Quality
The network consists of four monitoring units placed 2.3–4.8 km from the oil center. The sites were chosen according to a model that predicted the spread of emissions from the oil center. The air-quality-monitoring stations were installed outside the plant to continuously identify the effects that production activities have on the quality of the air and to provide operational warnings to avoid any negative effect on the surrounding territory.
Each unit is provided with computerized instruments, allowing continuous monitoring of the levels of carbon mon-oxide, hydrogen sulfide, sulfur dioxide, ozone, nitrogen oxides, benzene, toluene, xylene, methane, nonmethane gases, volatile organic compounds, polycyclic aromatic hydrocarbons, and radon, and monitoring of meteorological standards (e.g., wind speed and direction, rainfall levels, humidity, temperature).
The data received continuously from the monitoring units are reported in real time on the Web and in the control room of the plant and are compared continuously with information on pollution standards taken from the chimneys of the oil center.