bluuebunny/crossref_metadata_2025_split huggingface dataset:
Strategic Health Management
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 127068, ’Application the Strategic Health Management,’ by Filippo Uberti, SPE, Erasmo Macera, Simone Mortara, SPE, and Guillermo Gomez, SPE, Eni E&P, originally prepared for the 2010 SPE International Conference on Health, Safety, and Environment in Oil and Gas Exploration and Production, Rio de Janeiro, 12-14 April. The paper has not been peer reviewed.
Eni E&P works in complex operating environments, interacting with host communities and sharing their health and social problems. Strategic health management (SHM) introduces a systematic approach in each phase of the project life cycle to improve the health status of the workforce and their families and to promote/sustain lasting improvements to the health status of host communities. The approach has been used in various countries through initiatives aiming at development of local primary-health-care systems and/or control of specific endemic diseases.
Introduction
The objective of the SHM process is to pay attention to priority ill-health determinants within the host community and participate in their solution. Health-needs priorities, which sometimes need to be addressed, urgently would be faced more effectively and efficiently if a bottom-up approach could be used in the identification and planning process. Meaningful project design could be devised and thus attract whatever funding that might be available.
Investment in community health programs should be among the primary responsibilities of the local government. Although the decision on where and how much to invest in community health programs could be a matter of debate, it is (in line with self-reliance and -determination principles) the full responsibility of local authorities.
Because the objective of cooperation is to support partner countries in the development and implementation of their existing health policies and community health programs, the industry operators may choose to assist the local governments at various levels and in different ways.
Such assistance may take the form of direct or indirect investment, or could occur through more-traditional philanthropic corporate contributions. In all cases, the decision on whether to invest and how much to invest is up to the company. Actually, the contribution of a strong private/public partnership to health-system development is essential for a socially responsible company.
Prioritize Stakeholders
Timely and lasting improvements in community health are difficult to achieve and do not occur passively. Members of industry, sharing common principles and a common vision, must be prepared to engage host governments and other key stakeholders actively in cooperative consultation to plan actions that can achieve the desired outcomes. Planning and coordinating such interactions are critical over the life of a project.
Comments: Global Demand Surge
Authors: Donnelly John 
Published: February 2015

Editor's column
Energy statistics continue to confirm oil and gas industry conventional wisdom of the past several years—that global consumption shows no sign of stopping, which will put additional burdens on the industry and its people to pro-duce more energy amid challenging conditions.
Last year, world energy consumption grew 5.6%, the largest percentage increase year over year since 1973, according to the BP Statistical Review of World Energy 2011, a well-known annual report on energy data and trends. Demand grew for all forms of energy in all regions. This reflects a sharp reversal of what happened in 2009, when countries across the globe were feeling the effects of recession. That year, global energy consumption decreased for the first time in 30 years, but that appears to be just a temporary dip in a longterm trajectory of rising demand in both industrialized and developing countries.
Total consumption of energy surpassed the pre-recession peak of 2008, according to the BP report, and energy consumption is now growing faster than the world economy. China and India, whose demand did not slow during 2009, are showing an even stronger thirst for all types of energy. China’s share of global energy consumption now stands at 20%, making it the largest consuming country in the world, ahead of the US.
Average oil prices in 2010 were the second highest on record, but that did not deter demand growth. Prices for natural gas, though, which is a much less fungible commodity, varied from region to region. Gas prices remained weak in North America because of the enormous growth in shale production.
The outlook for gas appears bright. The International Energy Agency (IEA) recently offered the idea that the world could be entering a “golden age of gas” led by the growth in unconventional production. It predicts that over the next 25 years, 40% of global gas production will be from unconventional sources. Again, China is the leader. The IEA believes that China’s gas consumption could rise where it would equal total European Union demand by 2035.
An interesting phenomenon is the growth in shale oil in North America. The IEA recently revised its expectations for US oil production, and now predicts that US oil output will rise 1 million b/d by 2016 because of the increase in unconventional oil production, an offshoot of the shale gas surge. That figure could climb to 2 million or 3 million b/d by 2020, the IEA said. The suggestion is that the technology that has unleashed the shale boom could offer the same benefit for the oil side. The US Geological Survey estimates that the largest shale oil deposit in the US, the Bakken in North Dakota, could contain as much as 4 billion bbl of recoverable oil, and the Three Forks formation nearby could contain 2 billion bbl in recoverable reserves.
Growing Offshore Water Production Pushes Search for Subsea Solutions
Authors: Rassenfoss Stephen 
Published: February 2015

There are strong arguments for moving water processing from deepwater platforms to the seafloor in many fields. There need to be, given the daunting challenges to doing so.
One of the prime targets is older offshore fields producing more water than oil. When the water treatment facility on the topside reaches its capacity, it puts a cap on oil output. The rising water cut increases the force needed to lift a production stream holding ever less oil, as the pressure in the reservoir declines.
Ultimately the natural force isn’t enough to lift the water and oil from deepwater fields, which will mean the end of production if nothing is done. “When you can’t get it to the surface, you are left with nothing, unless you have got a way to pump it,” said Tim Daigle, senior project engineer at Fluor Offshore Solutions. There are two ways to do that: Increase the lift with pumps, or reduce the load by removing the water on the seafloor and disposing of it there.
After nearly two decades of development and testing, the latter option is beginning to emerge as an alternative. Oil companies are turning to subsea processing for projects that are challenged by the economics, looking for ways to make them profitable, or to improve their results, said Mike Robinson, a sales and marketing manager at FMC Technologies, which is a leader in this area.
Statoil’s Tordis field offshore Norway shows the upside and downside of subsea water separation. The company predicted the combination of subsea water processing and improvements in the pumping system on its Gullfaks C platform would increase ultimate production by 35 million BOE, pushing the field’s recovery rate from 49% to 55%. The design is based on what Statoil learned from its earlier pilot test installed on its Troll C platform in 2001, which is still processing 50,000 bbl a day and reinjecting the water into an aquifer.
Rune Ramberg, chief engineer of sub-sea technology at Statoil, said there are many reasons for the Norwegian company’s push to develop subsea water treatment systems. It has long relied on subsea completions. Developing Arctic resources will require alternatives to offshore platforms, which are vulnerable to ice. And most importantly: “We are not making money transporting water,” Ramberg said.
Managing Use of Local Content in Upstream Oil and Gas
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 140870, ’Managing Use of Local Content in Upstream Oil and Gas,’ by Jessica M. Marshall and Mark A. Serwinowski, SPE, MetaVu, prepared for the 2011 SPE European Health, Safety, and Environmental Conference in Oil and Gas Exploration and Production, Vienna, Austria, 22-24 February. The paper has not been peer reviewed.
As new markets develop and host countries develop local-content policies and performance expectations, oil and gas development companies face increasing complexities in supply-chain integration of local content. In many instances, performance assurance with local-content-performance expectations is becoming a threshold for obtaining and/or maintaining a company’s social license to operate. This paper chronicles one company’s approach to leverage local content as part of their supply-chain-management strategy to grow capacity while managing and fulfilling stakeholder expectations.
Introduction
Supply-chain management is becoming increasingly vital for ongoing operations in the upstream oil and gas sector. How individual organizations manage and train their suppliers can result in dramatic differences in performance. Given that, on average, upstream operators more-heavily leverage their suppliers, who these individuals are, what screening criteria they must meet, how they are managed, and how their performance is tracked are critically important questions.
In certain circumstances, use of local content to fulfill demanding schedules is not only encouraged from a social-responsibility perspective, but is a requirement for meeting deadlines. However, use of local content should be managed with a very specific engagement strategy to ensure that health, safety, and environmental performance expectations are not compromised.
Background
The use of local content (i.e., indigenous companies that conduct manufacturing or production services in the oil business), while required in cases of remote operations, can have positive benefits for the organization and for the host country/region. Effective use and training can result in transfer of knowledge, economic diversification, and long-term viability for the host region. But benefits also can be realized by the company.
While there are tangible benefits for the host country/region and for the organization, the use of local content should be managed proactively and be part of an overall supply-chain-management strategy. Five criteria have been established as key success factors.
Policy expectations and targets must be realistic and go hand in hand with capacity building
Content development must be based on global competitiveness, rather than preference
Contracting strategies are critical channels of content transfer and development
Content development must involve risk assessment regarding health, safety, and environmental standards, and regarding business risks including supply capacity, quality, delivery schedule, cost effectiveness, and profit generation
Spectrum: Great Rewards
Authors: Thakur Ganesh 
Published: February 2015

President's column
As I approach the end of my term as SPE president, I reflect not only on the past year but also on what led up to this wonderful year. I think about how SPE has affected my life in so many ways, all of which stem from three simple decisions.
First was my decision to join SPE. How do individuals determine value, and why do they choose to belong to a professional organization such as SPE? For me, it was a natural decision. I would be working in one of the most important careers in the world; in what other profession can you make a difference in the lives of millions of people every day? It logically followed that I wanted to be the best I could in that career. I have always viewed SPE as the foremost professional association for those working in oil and gas exploration and production (E&P). With its many technical resources (including its unrivaled collection of technical papers, its respected magazines and peer-reviewed journals, and its excellent conferences); the commitment exemplified by its mission, vision, and values; and its ability to connect E&P professionals globally, SPE was the best association to help me achieve my goal.
Second was the decision to learn. Why do people seek continuing education, and how can a membership organization such as SPE meet their needs? I took continuing education courses to keep up with the advancements in technology and to continue to sharpen my skills to become more productive and prolific in my work. I was privileged to take SPE short courses taught by world-class professionals such as Dr. Aziz Odeh. I kept learning more and more, especially early in my career. During 1990–91, I started to teach a course on integrated petroleum reservoir management with Dr. Abdus Satter, and, later, we wrote a textbook on this subject that became popular in the industry and with many universities around the world. Although I learned a lot by taking SPE short courses, I learned even more from teaching courses attended by some of the best minds in our industry. I remember, for instance, a course in the 1990s that included Bob Schneider (he passed away a few years ago), retired from Shell, and W. John Lee, a very distinguished professor from Texas A&M now at the University of Houston. This was one of the best courses I have ever taught because we not only taught the course but we also facilitated an enriched discussion that led to a superb learning experience for all the participants, including me.
Advances in Measuring Permeability Address Shortcomings of Crushed-Rock Technique
Authors: Wilson Adam 
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 152257, ’Advances in Measurement Standards and Flow Properties Measurements for Tight Rocks Such as Shales,’ S. Sinha, SPE, E.M. Braun, SPE, Q.R. Passey, SPE, S.A. Leonardi, SPE, A.C. Wood III, T. Zirkle, SPE, J.A. Boros, SPE, and R.A. Kudva, SPE, ExxonMobil Upstream Research, prepared for the 2012 SPE/EAGE European Unconventional Resources Conference and Exhibition, Vienna, Austria, 20-22 March. The paper has not been peer reviewed.
The most commonly used industry method for measuring permeability is the Gas Research Institute (GRI) technique or its variants, which involve the use of crushed samples. The accuracy of such techniques, however, is questionable because of a number of inadequacies, such as the absence of reservoir overburden stress while conducting these measurements. In addition to the questionable accuracy of crushed-rock techniques, studies have indicated that there is significant variability in results reported by different laboratories that use crushed-rock techniques to measure permeability on shale samples. The complete paper presents a robust steady-state technique for measuring permeability on intact tight-rock samples under reservoir overburden stress. These standards can be used to calibrate any permeability-measurement apparatus used on intact tight-rock samples, such as shales, to enable delivery of consistent results across different laboratories.
Introduction
For low-permeability reservoirs such as shales, the GRI method is popular because of the relatively quick times associated with the measurements as a result of the increased surface area available and because of the perception that measurements on intact low-permeability plug samples by use of well-established methods such as steady state or pulse decay could take such long times that it would make such measurements impractical. However, using crushed rock for measuring permeability has a number of inadequacies, resulting in skepticism associated with the accuracy of such measurements. Perhaps the most serious drawback of the crushed-rock method for measuring permeability, as presented in a number of studies, is the wide variability in results reported by different vendors, with results that could differ by as much as three orders of magnitude.
Shortcomings of GRI Technique of Measuring Permeability
The GRI, or crushed-rock, technique for measuring permeability is a relatively fast method for measuring permeability on low-permeability samples, but it has the following shortcomings.
Absence of Overburden Stress. The GRI technique is implemented on crushed rock samples, and, therefore, these measurements are not conducted at reservoir overburden stress. Ignoring the effect of overburden stress while measuring the permeability could lead to significant discrepancy between permeability measured in the laboratory and in-situ permeability.
Autonomous Underwater Vehicles Ease Deepwater-Field Integrity Management
Authors: Wilson Adam 
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper OTC 22438, ’The Role of Autonomous Underwater Vehicles in Deepwater Life-of- Field Integrity Management,’ by Dan McLeod and John Jacobson, Lockheed Martin, prepared for the 2011 Offshore Technology Conference Brasil, Rio de Janeiro, 4-6 October. The paper has not been peer reviewed.
Integrity management of deepwater fields requires routine general visual inspections of critical infrastructure. To date, the only way to conduct general visual inspection is through the use of remotely operated vehicles (ROVs). Deepwater ROV spreads are large and heavy, requiring large support vessels and a significant number of personnel at sea. The capabilities of unmanned underwater vehicles have been enhanced through developments in autonomous technology, progressing to the point that autonomous underwater vehicles (AUVs) can now routinely conduct general visual inspection of subsea facilities.
Introduction
AUVs are smaller than ROVs, require less deck space, have fewer operators, and are free from precise-positioning requirements of the support vessel. Advances in autonomy, coupled with unique mission sensors, greatly reduce the human interaction required when collecting images of oil and gas underwater infra-structure. These factors dramatically reduce the operational cost of a deepwater inspection.
The Marlin AUV system recently completed a series of tests in the US Gulf of Mexico, demonstrating autonomous change detection of a fixed off-shore platform. Benefits of autonomous inspection include
Reduced cost of operations
Faster inspection
Automatic change detection
Georegistered inspection data
Simultaneous operations from a single support vessel
Large standoff distances from the facility being inspected
Increased safety of operations
Reduced environmental impact
Reduced specification requirements on support vessel
Subsea Integrity Management
A key element in any integrity-management program is regular in-service inspections. As the industry moves into deeper and harsher environments, challenges faced by operators include the high cost of subsea inspection and the limited inspection intervals available. Inspections provide a snapshot of the structural health of the system. An ROV inspection of a deepwater facility can provide visual evidence of structural degradation, impact damage, corrosion, valve damage, leaks, vibration, and other structural damage. Benchmarking the condition of subsea equipment following installation and tracking its status over time can provide a history of the deterioration rate.
Deepwater Inspection Tasks
Visual inspection of deepwater facilities routinely employs ROVs piloted by operators on the surface while recording high-definition video data. Video inspections include equipment that is often spread over many square kilometers, requiring the support vessel to maneuver for days. Inspection speed is totally dependent on the coordinated movement of the ROV and support vessel and on the skill of the ROV pilot.
Aging and Life Extension: KP4 Inspection Program - The First Year
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 145518, ’KP4: Aging and Life-Extension Inspection Program - The First Year,’ by Alexander Stacey, UK Health and Safety Executive, prepared for the 2011 SPE Offshore Europe Oil and Gas Conference and Exhibition, Aberdeen, 6-8 September. The paper has not been peer reviewed.
With a significant proportion of the UK’s offshore infrastructure having exceeded the original design life, the aging population of offshore installations presents a growing challenge to safety. Aging is characterized by deterioration that, in the severe operational environment offshore, can have serious asset-integrity consequences if not managed properly. The UK Health and Safety Executive (HSE) Aging and Life Extension Inspection Programme, also known as Key Programme 4 (KP4), was launched in July 2010 to the UK offshore industry.
Introduction
The purpose of KP4 is to
Determine whether the risks to asset integrity, which are associated with aging and life extension, are being controlled effectively.
Raise awareness of the need for specific consideration of aging issues as a distinct activity within the asset-integrity-management process and of the need for senior management to demonstrate leadership on this matter.
Identify shortcomings in duty-holder practices in the management of aging and life extension, and enforce an appropriate program of remedial action.
Work with the offshore industry to develop a “best-practice” common approach to the management of aging installations and life extension.
More than 50% of offshore installations in the UK sector of the North Sea have exceeded the original design life, typically specified as 20 or 25 years, and this proportion is increasing steadily with time. The majority of installations are likely to remain operational for many years, and, thus, the aging offshore infrastructure presents a growing challenge, particularly as reserves decline and the nature of companies in the market changes. In the extreme case, failure could cause the total loss of an installation with little chance of survival. Thus, the management of aging and life extension must be an integral part of the asset-integrity-management system (AIMS) to ensure continued safe performance.
Integrity management of aging installations and successful implementation of an asset-integrity-management plan for life extension depend on understanding the degradation processes, on accurate knowledge of both the condition of the asset and its response in the aged condition, and on an implementation strategy to deal with the increasing risk of failure with time, which enables the greater likelihood of deterioration to be predicted, detected, and assessed. Risk-based goal-setting regulations, supporting guidance, industry standards, risk assessments, and performance standards provide the basis on which owner/operator policies can be developed.