bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Method to Assess and Classify HSE Standards
Authors: Aas Andreas Lumbe , Skramstad Torbjørn 
Published: March 2009

Abstract
We established metrics to assess HSE standards for the purpose of making cross standard comparisons to rank the standards and to predict resource requirements. We assessed six international safety standards, thirteen parts in total, to determine their degree of goal-based or prescriptive, generic, and process-oriented approach. We also recorded size, year of publication and the number of normative references. These standards were published in the period 1994-2006 and were selected because they were normative references in the working environment standard NORSOK-S002, developed by the Norwegian petroleum industry.
As new technologies emerge and the use of software in safety-critical systems increases, it can be challenging to provide effective, efficient and easy-to-use safety standards. Thus has the use of process-oriented and goal-based safety standards emerged where a prescriptive approach was inappropriate. Typically, more experienced personnel will be required to effectively apply goal-based standards compared to prescriptive ones.
We plan to use this framework to gain an overview of the use of goal-based versus prescriptive standards to predict resource requirements, such as personnel's competence.
The results revealed that our selection included both prescriptive and goal-based standards. We expected recent standards to be more goal-based than older ones, but a Spearman analysis revealed no correlation. We did, however, observe a weak correlation indicating that more recent publications were larger in size (0.55). We also observed that the degree of goal-based approach in a standard correlated negatively with the number of normative references (-0.45) and with the size (-0.35). Reasons for this can be that goal-based standards typically contain fewer specific requirements, which reduce the need for normative references and thus size.
We conclude that our framework appears appropriate to assess HSE standards and that we have established valid metrics for such assessments.
Effective safety standards are important in order to ensure safe systems at an acceptable cost. The rapid development of new technology, combined with a growing number of standards, calls for a systematic approach to assess, classify and compare HSE standards to predict their impact.
Environmental Performance of the Exploration and Production Industry: Past, Present, and Future
Authors: Godec Michael L. 
Published: March 2009

Abstract
This paper builds upon past work1 to document the technological progress made by the oil and gas exploration and production (E&P) industry and the environmental benefits realized from this progress. The improvements in environmental performance made by the E&P industry is documented, industry and societal trends examined, and technological advances contributing to its performance highlighted. The paper describes how company environmental performance has evolved from a necessary activity to comply with regulatory requirements to a major factor differentiating companies to stakeholders, including customers and the communities within which they operate -- or wish to operate. Several new concepts of environmental performance are introduced, particularly relating to extracting environmental value from existing infrastructure. Finally, the paper concludes by describing the likely key future role the E&P industry will play in addressing arguably the most important environmental issue of our time – global climate change.
Improving Safety Management in the Exploitation of Mature Fields in a Complex Social Environment
Authors: Torraca L. , Ferrari M. 
Published: March 2009

Abstract
The Southern Argentina YPF Business Unit, UNAS, develops a wide Exploration and Production activity in more than twenty oilfields, dispersed in a vast area of twenty thousand square kilometers within the San Jorge Basin. The daily activity involves ten thousand workers under rigorous climatic conditions.
The UNAS E&P operation is carried out in mature oil fields, some of them under continuous operation since 1907.
In the last five years under a stage of changes in respect to a new prevailing social model, UNAS emphasized the need to improve its Safety Model, in order to deal with new and relevant elements of consideration: new government regulations, increasing number of union conflicts, social claims, and certain demands to increase workforce by poorly qualified personnel. Under this relevant context, UNAS defined and implemented a very challenging and solid model aiming to add value to the stakeholders by targeting a few critical elements of the Safety Culture.
This paper provides a case of study of how the organization faces new opportunities of improving safety performance in a turbulent environment by means of accomplishment of a strong Health and Safety Policy and specific concrete actions.
Risk Assessment as a Tool in Establishing the Requirement of Subsea Isolation Valves in Subsea Pipelines
Authors: Dhar Rahul 
Published: March 2009

Abstract
For offshore oil and gas installations, one of the major hazards identified is the possibility of a hydrocarbon leak on the pipeline side of the riser Emergency shutdown valve (ESDV). The consequences of such an event can be catastrophic as the subsea pipelines are generally several kilometers long and contain large inventories.
In order to prevent the backflow of the hydrocarbon inventory from the subsea pipeline in the event of a leak on the pipeline side of the riser ESDV, the requirements of installing a Subsea Isolation Valve (SSIV) are assessed. The purpose of installing a SSIV in the subsea pipeline is to limit the duration and severity of release which can in turn potentially reduce the risk to personnel, asset and environment. In addition to this function, the subsea isolation system also provides an alternative means of isolation in the event of failure of the topsides isolation system. In some instances, however, the cost and operational impact of installing an SSIV may outweigh these benefits.
The assessment for benefits versus non-benefits of installing a SSIV are carried out using Risk Assessment techniques and the decisions are generally based on Cost Benefit Analysis (CBA). The use of risk assessments in establishing the requirement or non-requirement of SSIV's in the subsea pipelines is currently the best tool available for the oil and gas industry. However, these assessments and the conclusions drawn there from should be based on a holistic approach considering personnel, asset and environmental risk, production availability, operational impacts, SSIV reliability and the cost benefit analysis.
The purpose of this paper is to elaborate on the risk assessment process undertaken for establishing the requirement or non-requirement of a SSIV in a subsea pipeline. It further cautions the assessor about possible pitfalls and identifies possible challenges in such assessment processes.
Well Integrity Management: A Systematic Way of Describing and Keeping Track of the Integrity Status for Wells in Operation
Authors: Haga Jarle , Corneliussen Kjell , Sorli Folke 
Published: March 2009

Abstract
Talisman operates several fields on the Norwegian Continental Shelf (NCS), many of these mature fields are taken over at the end of their design life. These old fields represent challenges with respect to well integrity and overall profitability.
Talisman is a member of the Well Integrity Forum (WIF), a co-operative effort between the operating companies on the NCS to define a unified approach for handling well integrity. Using WIMS and the WIF recommendations together with internal guidelines improves Talismans ability to handle well integrity issues throughout the production phase of a well and in compliance with regulatory requirements.
This paper describes how Talisman Energy Norway (Talisman) manages well integrity for their assets, and discusses the benefits, challenges and lessons learned from implementing a well integrity management system, focusing on technical and organizational aspects.
Restoring Sagebrush Habitat in the Pinedale Anticline Natural Gas Field in Wyoming
Authors: Sewell H. James , Carr Richard S. 
Published: March 2009

Abstract
Disturbed areas in the Pinedale Anticline natural gas field of southwestern Wyoming are being restored using native plant species that are beneficial in critical sage grouse and ungulate habitat. A new seed mixture was developed to re-establish native plant species in reclaimed areas, replacing the grass-dominated seed mixes that have been utilized in the past, and returning these areas to productive habitat in a more timely manner. Testing and monitoring of various seeding methods, soil amendment use, topsoil stockpile management and temporary stock fencing has been ongoing since the fall of 2004. Observations to date indicate successful re-establishment of sagebrush as well as various grasses and forbs that should provide habitat for sage grouse and ungulate populations in the vicinity of the current natural gas field development. Several seeding methods have proven successful in the application of the native seed mixture, promoting germination of young plants during the next growing season. It is unclear at this time if the use of soil amendments and biostimulants has provided more success in native plant establishment than if these materials were not used. Temporary fencing of reclaimed sites during the first several growing seasons has provided protection of seedlings from stock grazing pressures, although wildlife continue to utilize the reclaimed areas for forage and habitat.
Guidelines for a Regulatory Framework to Accommodate Geological Storage of CO2 in Alberta
Authors: Zeidouni M. , Moore M. , Keith D. 
Published: March 2009

Abstract
The principal drivers of climate change are likely to be CO2 emissions caused by use of fossil fuels. A variety of methodologies have been proposed to cut these emissions. A preferred method is CO2 Capture and Storage in geological formations (CCS). Despite exceptional CCS potential in the Province of Alberta, there are legal and regulatory issues that must be resolved to allow its implementation. Without these changes there will not be enough certainty to enable the industry to make appropriate decisions that encourage investment.
Existing regulations of Alberta in oil and gas sector designed to regulate acid gas disposal provide a basis for regulating geological storage of CO2. However, these regulations cannot be directly used to handle huge CO2 storage volumes compared to the acid gas disposal amounts. Disposal of CO2-rich acid gas streams is mainly regulated by the directives of Alberta Energy Resources Conservation Board (AERCB).
Guidelines are provided in this paper to show how these regulations can be the basis for geological storage projects. The guidelines are given for different CO2 storage project stages of: planning and design, operation, closure, and post-closure. The guidelines presented in this work are applicable to any regulatory regime for assessment and management of the risks associated with CO2 storage activities.
At the planning and design stage of the project, certain criteria for site selection are proposed, including comprehensive reservoir characterization and modeling for risk assessment and performance prediction of storage project. The regulatory regime can then use performance-based and procedural regulations to ensure sufficient data is acquired and a model with a specified confidence limit is available.
Risk of leakage is highest during the operation stage because the formation pressure is the highest at this stage. Considerations to be made by the regulatory regime to ensure containment of the CO2 during this stage are proposed. Guidelines are given on what should be considered by the regulatory regime to ensure sufficient level of monitoring.
Implementing these changes encourages, but does not guarantee the regulatory system to be compatible with future technologies and adapt to changes in risk and remediation.
Dry-Polymer Blending Eliminates Need for Hydrocarbon Carrier Fluids
Authors: Weinstein Jeremy , Phillippi Max , Walters Harold G. 
Published: March 2009

Abstract
This paper presents methods, materials, and equipment that can be used to mix and apply viscous proppant-carrying fluids, on-the-fly, to support hydraulic fracturing processes using a dry-polymer blender. This dry-polymer blending system (DPBS) replaces the liquid-gel concentrate (LGC) mixing method, which requires premixing gel-producing powders with a hydrocarbon carrier fluid.
The equipment and methods described have contributed to a cleaner environment without imposing any cost increases or wellsite expansion on the operating company. The on-the-fly dry-gel blending process is compatible with existing fracturing technology, and has helped enable environmentally responsible technology development.
The fracturing fluid product used in this process is based on dry powders and does not contain hydrocarbon carrier fluids. Dry-polymer blending enables the use of new gel systems that work well in produced waters. This type of blending can be applied in any hydraulic fracturing operation requiring preparation, blending, and pumping of a viscous fluid to suspend proppant for transport to created fractures. The DPBS uses a trailer with a weigh system and continuous viscosity monitoring to help ensure job quality. Handling of the gel powder can be accomplished without dusting.
Strategies for CO2 Reductions in the U.S. Enhanced Oil Recovery Production Segment: Utilizing Energy Efficiency as the First Step
Authors: Hamilton Gerry 
Published: March 2009

Abstract
This paper presents aggregate level energy consumption data for the U.S. Oil and Gas Production industry to illustrate the significant contribution that energy consumption makes to total industry greenhouse gas emissions. The potential for energy savings through the implementation of energy efficiency measures is then presented as a viable strategy for reducing industry emissions. Total energy consumption data and energy savings estimates are converted to equivalent CO2 emissions to present an estimated baseline for the industry associated with energy consumption and to illustrate the potential reduction in emissions. The data used for analysis come from publicly available sources and are used to derive estimations only. The analysis reveals that the best opportunities for energy savings, and associated CO2 emissions, are in the enhanced oil recovery (EOR) sector of the industry. Disproportionately high production energy intensities linked to EOR processes enable a relatively few efficiency upgrade projects to delivery significant savings.
Experiences from California energy efficiency programs targeting oil and gas producers are highlighted. Insight from these programs is used to identify proven energy efficient technologies, energy savings expectations, and the potential for CO2 emissions reductions.
Reducing Centrifugal Pump Noise and Vibration on Cementing Equipment
Authors: Coffman Ken , Neal Greg 
Published: March 2009

Abstract
Sound and vibration studies have been conducted on cement mixing and pumping equipment to identify the loudest components so that the reliability and efficiency of noise and vibration reduction work can be improved.
During stages of the mixing process, the variable-speed centrifugal pump has minimal flow through it, yet it maintains high pressure. This pressure causes discharge cavitation that forms bubbles that collapse on the outside of the impeller. This cavitation is thought to be the main cause of noise and vibration from the pump.
The centrifugal pump supplying water for the cement-mixing process had sound pressures of up to 105 dBA ref 20μPa, power spectral densities (PSD) of up to 7.3 g2/Hz RMS, and can be heard over the unit's diesel engine noise. Hence, this location was selected as the best place to start noise/vibration reduction.
A standard centrifugal pump was tested and, in one test, was modified to have a smaller impeller and, in another test, sound attenuation blankets were installed on the pump. Sound and vibration measurements were completed on a test stand as well as on a cementing unit.
The testing with the modified impeller showed significant noise and vibration reduction. The sound pressure level was reduced approximately 13 to 16.5 dB when the impeller diameter was reduced from 12 in. to 11.25 in.; there was also a significant decrease in the overall vibration level of the unit. A corresponding loss of maximum pressure from 111 psi to 94 psi was observed but was not considered significant to the cement-mixing process. This pressure loss was overcome by increasing the speed of the pump, which caused a minimal increase in the noise and vibration signature. The sound pressure level was reduced 1.5 dB with the sound attenuating blankets installed.
Evaluating the Environmental Implications of Hydraulic Fracturing in Shale Gas Reservoirs
Authors: Arthur James Daniel , Bohm Brian K. , Coughlin Bobbi Jo , Layne Mark Alan , Cornue David 
Published: March 2009

Abstract
Exploration, drilling and production of shale gas plays such as the Barnett, Fayetteville, and Haynesville have transformed the unconventional gas industry. These and other existing and developing plays have had unimaginable economic impacts to many regions, created tens of thousands of jobs, and have generated royalty payments to a variety of state and local governments as well as many individuals. At the core of shale gas development are two key technologies: horizontal drilling and hydraulic fracturing. Techniques used to hydraulically fracture horizontal wells completed in shale reservoirs often require larger volumes of fracturing fluid than might be common for conventional, vertical well stimulations. The rapid development of shale gas across the country has created concerns on issues such as the use of infrastructure and environmental impacts. Specifically, the common practice of hydraulic fracturing of these shales has attracted critical interest regarding risks potentially posed to groundwater and surface water. This paper will present a summary and evaluation of the environmental implications of hydraulic fracturing in shale gas reservoirs, with examples from multiple basins.

Introduction
Natural gas production from tight shale formations, known as "shale gas", is one of the most rapidly expanding trends in onshore, domestic natural gas exploration and production. In some areas, development of shale gas resources is bringing drilling and production to regions of the country that has previously seen little to no oil and gas development activity. In plays like the Barnett Shale of Texas, development is occurring in urban and suburban areas where both operators and regulators are adapting to this new environment. Shales are the most abundant sedimentary rock in the Earth's crust and are present across the U.S. (Figure 1).
Shales have been sources of natural gas in small but continuous volumes since the earliest years of gas development. The first producing gas well in the U.S. was completed in 1821 in Devonian-aged shale near the town of Fredonia, New York (Harper, 2008). Early sources of natural gas were shallow gas wells that were from dug wells and natural gas seeps (NY DEC, 1992). Shallow wells and seeps were capable of producing small amounts of natural gas which were used for illuminating city streets and households (Frantz and Jochen, 2005). These early gas wells played a key part in bringing illumination to the cities and towns of the eastern U.S. (Harper, 2008). In contrast, modern shale gas development has become a technological play, in which development is facilitated by the technological advances the oil and gas industry has made in hydraulic fracturing and horizontal drilling over the last two decades.
Anti-Collision Risk Management Standard for Well Placement
Authors: Poedjono Benny , Lombardo Guy J. , Phillips W. 
Published: March 2009

Abstract
Complex drilling programs in crowded downhole environments are increasingly common today, placing a premium on effective techniques for avoiding wellbore collisions. The costs of such incidents, both in financial and safety terms, can be extremely high. The authors have developed a comprehensive and effective approach to wellbore collision avoidance, as confirmed by a number of consistently successful projects. Based on their experiences in the field, the authors believe the time has come to establish an industry-wide standard for evaluating, minimizing and mitigating well collision hazards. This paper will outline their approach and provide case studies illustrating the high cost of such collisions and the value of an effective process for identifying-and eliminating or reducing-their likelihood.
The approach described is flexible enough to accommodate the different challenges each unique field presents, and has proven equally effective in projects ranging from simple vertical wells to crowded land pads, offshore platforms, deepwater/subsea and fishbone multilateral designs. Well position uncertainties are determined by using survey error models from the Industry Steering Committee on Wellbore Survey Accuracy. Drilling program recommendations are based on the status and conditions of adjacent wells and the nature and magnitude of potential risks associated with a collision. Developing a standard based on this approach will equip the industry to achieve increasingly complex and ambitious goals without compromising safety or incurring unacceptable losses or risks by ensuring the targeting of the correct limited resources and expertise where they are most needed.
Time to Protect: Layout Methodology for Safe Simops in High-Pressure, High-% H2S Facilities
Authors: Blyth A. 
Published: March 2009

Abstract
Growing numbers of projects are proposing to produce fluids contaminated with Hydrogen Sulphide (H2S) at high concentrations, and operating at high pressures.
The scale of toxic impact from high pressure, high-% H2S leaks is very significant, and this is driving changes to layout strategy. Large separation distances are being implemented in order to mitigate toxic fatality impact, particularly for simultaneous production and construction / maintenance operations (SimOps). A new methodology for layout has been developed for SimOps in high-sour facilities, based on "time to protect", which provides a risk-based approach to equipment or area segregation that buys time for emergency escape prior to impairment by incoming H2S. The methodology combines physical effects modeling and QRA, emergency response, and the "sour mindset" competency of personnel in response to an H2S release. It can also be used as a decision-making tool to determine the level of H2S training required and personal protection (such as escape breathing sets) for different SimOps areas and activities around a facility.
There is potential for application of the layout methodology in development of projects that will handle H2S at high partial pressures, such as:
Sour Enhanced Oil Recovery (EOR) Acid Gas Injection (AGI) Sour gas processing facilities with high-% H2S in the feed stream.
The material is applicable in both on- and offshore locations. The result is a layout that has significantly larger spacing than seen in "standard" facilities. There are many cost, schedule, operability and maintainability implications to consider; the ALARP balance is not simple. This type of layout approach requires front-end implementation in projects and early operations input in order for optimal benefits to be achieved.
The layout methodology can help to significantly reduce toxic exposure fatality risk, particularly for groups of workers. This can reduce a company's risk of reputation loss associated with large-scale multiple fatality accidents; a key factor for consideration in a sour venture where a large-scale H2S release can rapidly engulf a widespread area with toxic gas.