bluuebunny/crossref_metadata_2025_split huggingface dataset:
Delivering Projects during a Skills Shortage: Lessons Learned from the UK Nuclear Industry
Authors: Warwick A. , Penney John , Krishna K. 
Published: April 2012

Abstract
A recent Economist Intelligence Unit report on the future of the oil & gassector canvassed the views of nearly 200 board-level executives andpolicymakers on a range crucial industry affairs, from new investmentopportunities to future regulatory challenges and the rise of a new breed of'internationalized' national oil companies over the next decade.
One of the key findings from the subsequent round table discussion (facilitatedby GL Noble Denton) was that more needs to be done to develop the nextgeneration of oil and gas professionals. Faced with a period of investment andexpansion, the sector will come against challenges as a result of its failureto attract, recruit and retain highly talented people. The discussion concludedthat the industry needs to work more closely together to address the skillsproblem, rather than trying to pursue each others' technical staff. Withactivity set to rise in the sector, companies need to focus on introducing anddeveloping technical resource now, ensuring that the right talent is in placefor the future.
Atkins has been helping the UK nuclear industry to overcome similar challengesin recent years.
The UK nuclear supply base had been gradually declining over the last 20 yearssince the completion of the last power station at Sizewell. This has beencompounded by the hold placed on the deep waste repository and the prolongedhiatus between the Vanguard class submarine program and the Astute classSubmarines in the defense sector. This has led to government concerns that theUK capability would not be sustainable, with many of the current UK nuclearsupport needs more design and major project related than the consultancy typework of the last two decades. This requires a greater focus on technicalassurance and process compliance to ensure that project delivery and qualityrisk is managed appropriately.
This paper outlines the processes that Atkins is using to increase staffnumbers and develop its in-house technical expertise in response to the currentand anticipated needs of the UK nuclear industry; whilst at the same timeensuring technical quality is maintained and project delivery risk isminimized

Introduction
The UK supply base had been gradually declining over the last 20 years sincethe completion of the last UK nuclear power station at Sizewell, compounded bythe hold placed on the deep waste repository and the prolonged hiatus betweenthe Vanguard class submarine program and the Astute class Submarines in thedefense sector.
Over this period of time the industry has fragmented with the tier 1 providersoutsourcing much of their capability and reducing their core business torelatively small enterprises. This has led to a growth in small and medium sizeenterprises providing manpower substitution and specialist services to the tier1 providers. The current status of the supply base led to government concernsthat the indigenous UK capability would not be sustainable without significantinvestment.
Acid Gas Dehydration - Is There a Better Way?
Authors: Mckay Wayne , Maddocks Jim 
Published: April 2012

Abstract
Today, when acid gas containing significant amounts of carbon dioxide isprocessed for sequestration or EOR reinjection, it is typically dehydrated witha glycol absorption process. Three dehydration processes are examined by way ofan example case. The examination includes financial, physical, environmental, process, and operational comparisons. Pros and cons of the currently availableoptions are discussed and the paper demonstrates why glycol absorption is thethird best option for most applications - especially offshoreapplications.
To establish a baseline of understanding for acid gas dehydration processes, this paper first outlines why, when, and how much acid gas dehydration isrequired and relates that to current guidelines. The paper introduces adehydration method that is lower in both capital and operating cost, issignificantly smaller, has almost no emissions, and is easier to maintain thanthe alternatives. The first commercial installation of this technology went onstream in February 2011 at a 180 MMscfd natural gas processing facility inWestern Canada.
Marlim 3 Phase Subsea Separation System - Challenges and Solutions for the Subsea Separation Station to Cope with Process Requirements
Authors: Orlowski Rene , Euphemio Mauro Luiz Lopes , Euphemio Mauro Lopes , Andrade Cynthia Azevedo , Guedes Flavia , Tosta da Silva Luis Carlos , Pestana Rafael Guimaraes , de Cerqueira Gustavo , Lourenço Igor , Pivari Alexandre , Witka Anderson , Folhadella Heloisa , Pacheco Leonardo , Kronemberger Steven , Vilela José 
Published: April 2012

Abstract
This paper presents the experience brought from the oil-water subsea separatorproject developed for the Marlim field, known as SSAO Marlim. Here, it will beaddressed the inherent arising challenges from a project of a subsea separationequipment, from the subsea mechanical design perspective, with special focus tothe additional requirements to the normally presented in conventional subseaequipment for oil and gas production.
It will be part of the discussion the architecture selected for the system andthe main challenges imposed by:–Separation process (gas-liquid, liquid-liquid and sand removal system);–Requirements for modularization, installation and retrieval of subseacomponents;–Installation concept.

Introduction
The oil-water subsea separator is installed in a water depth of approximately870m in the Marlim field, located in the Campos basin, Brazil. The subseaseparation station has an envelope of 29m length, 10.8m width, 8.4m height andan overall assembly weight in-air of 392ton, and it will receive productionfrom selected well, separate produced water from oil and sand and re-inject itinto Marlim production reservoir via a centrifugal pump. The water separationhappens into a Pipe SeparatorTM based on a gravitational concept, while waterpolishment to meet quality requirements, i.e. reduce oil content in water toacceptable levels for the re-injection into reservoir, is performed by cyclonicequipment. The equipment also has a sand management system which the main aimis to minimize the operational impact induced by solids production.
Figure 1 illustrates the oil-water subsea separation system of Marlim.
Floating CNG, A Simpler Way to Monetise Offshore Gas
Authors: Stenning David G. , Fitzpatrick John P. , Trebble Mark A. 
Published: April 2012

Abstract
Monetizing offshore gas by compressing and shipping in CNG carriers (FCNG) issimpler and in most cases, less expensive than liquefying and shipping in LNGcarriers (FLNG). Seaborne CNG transport requires essentially the sameinfrastructure as pipeline export, except that the gas is compressed into aship rather than a pipeline.
Significant investments are being made in engineering and implementing FLNGsystems. These FLNG systems are generally aimed at large field developments.FCNG provides a new way to add to the world's natural gas supply by allowingsmaller offshore gas fields to be economically exploited.
The key to making FCNG a robust and general solution for offshore gasexploitation is the availability of internationally approved CNG ships that canoff-take the gas and deliver it economically to markets within 2500 km. Theseapproved CNG ships are now available.
The paper will describe the major components of an FCNG system including thecapital and operating costs. It will also outline the principal advantages ofsuch a system compared to an FLNG system.

Introduction
Many offshore gas fields are too small or too remote to produce by pipeline toshore. The LNG industry has advanced to fill the need in respect of larger gasfields by creating an FLNG production concept where an LNG processing andrefrigeration plant, complete with LNG storage, is integrated into a ship orbarge and moored at a gas field. LNG ships are then used to offtake the LNG anddeliver it to markets, where it is stored and regasified as needed. FLNGprojects have many technical and economic challenges, and the recentannouncement of Shell's final investment decision for the Prelude FLNG projectis a testament to the work and commitment that the industry has invested inFLNG. However, a simpler and less expensive way to produce gas from many fieldsis to avoid liquefaction altogether and instead just compress the gas into CNGships, which then deliver it to regional markets. Marine CNG serves marketsthat fall between subsea pipeline markets and long distance LNG markets.
SS-Offshore Offloading Systems and Operations Bonded Flexible Oil Offloading Lines, A Cost Effective Alternative to Traditional Oil Offloading Lines
Authors: prischi Nicolas , Mazuet Francois , Frichou Adeline , Lagarrigue Vincent 
Published: April 2012

Abstract
In deepwater offshore fields where spread moored FPSOs are involved, theproduced oil is generally offloaded to shuttle tankers via Oil Offloading Lines(OOLs) connected between the FPSO and deepwater buoy. Until recently, two typesof Oil Offloading Lines (OOL) were used for the transfer of stabilized crudeoil between the FPSO and the offloading buoy: steel pipe or unbonded flexiblepipe. Since 2000 Trelleborg and SBM have been working on an alternativeoffloading solution made of bonded flexible hoses called TRELLINE™ (seereference [1]). This product can be adapted to a large range of applicationslike for the offloading of oil from a MOPUstor to a submerged loading system(SLS).
In September 2005, the TRELLINE™ was used for OOL for the first time for SNEPCOwho decided to supplement the existing Bonga OOL system with one 20" IDTRELLINE™ to match with ultra short delivery. In December 2006, the OOL wasinstalled with the SBM vessel Dynamic Installer (see reference [2]).
In July 2008, Total Exploration Production Angola (TEPA) decided to use theTRELLINE™ for the 18" ID OOLs of the Pazflor field. For Pazflor, the producedoil is exported from the FPSO to the buoy located 1,856m away, via twoidentical 18" OOLs of 2,070 m long, made of 175 hoses sections each. The OOLsare connected to the FPSO and the buoy by the means of gimbal tables thatdecouple the tension and bending loading. Specificity of Pazflor Trelline hoseswas their hig desing pressure equal to 50 bars that had required intensivequalification and testing program, and making Pazflor export lines a" world-first".
Based on past installation experiences on Bonga project (OOL) for SNEPCO in2006 and on Yme project (SLS) for Talisman Energy Norge in 2008, see reference[3]), a new installation method has been developed. A specifically designedpatented equipment was developed to ensure a safe and quick offshoreinstallation.
It comprises:An A-Frame designed to upend individual hose from deck to the fireline.An assembly platform designed for vertical assembly of the hoses.A large deployment wheel ensuring the transition from vertical to horizontalof the OOL at the sea surface.
In June 2011, the SBM vessel Normand Installer successfully installed the twoPazflor OOLs. The two OOLs were assembled and hooked up in less than 4 weeks(mobilizations included).
The TRELLINE™ OOL system demonstrated its advantages in term of design, procurement cost, lead time, installation efficiency and operationaladvantages. It will further demonstrate maintenance advantages.
Sand Face Completions Enter the Real Time Age with a One-of-a-Kind Downhole Visualization Tool
Authors: Grigsby Tommy F. , Jannise Ricki C. , Schwendemann Ken , Rubio Raymond , Towers Darrin 
Published: April 2012

Abstract
The operation of downhole sand-face tools has relied upon depth measurements, downhole indicators that use applied tension or compression noted on thesurface weight indicator, as well as hydraulic pressure in order to verifyservice-tool positions in relation to the sand-face assembly. This strategy hasworked well in the past. However, with field developments with increasing welldepths, higher-angled wells with increasingly complex geometry, and increasingintricacy in sand-face tool systems, the need for additional methods to aidtool operators in locating and communicating service-tool positions has becomeapparent. Also, modeling the effects of the pumped treatment on the tool systemand work string in real time will assist in understanding when, and if, thetool system will move out of position.
The introduction of multiple-zone one-trip sand-face completion systemsdeveloped for applications in the ultra-deepwater Lower Tertiary play of theGulf of Mexico has led to the development of a visualization tool that providesthe tool operator with additional information to validate conventionaltool-locating methods as well as providing a communication interface tocommunicate the tool information to others. This innovative visualization toolis a software program known as the " Real Time Visualization Service (RTVS)". The RTVS package provides detailed visualization of the entire sand-faceassembly, including the service string, providing the tool operator andobservers with another tool-location validation method along with anexceptional pre-job planning tool. The visualization software provides thecapability to monitor operations at the rig site or remotely from a real-timemonitoring site or home personal computer.

Introduction: Development Drivers for Real Time DownholeVisualization
There are a number of factors that have converged to drive the development ofthe real time downhole visualization capability. First, well depths and welldeviations are increasing. The Lower Tertiary play in the Gulf of Mexico haspotential well depths to 33,000 feet while other areas in the Deepwater GoldenTriangle (Brazil & Angola) (Gue, 2009) use horizontal sand face completionswith increasing horizontal lengths. Second, sand face completions have becomeincreasingly complex as interval lengths have increased and intervalsegmentation is required to effectively stimulate the reservoir. Third, thehigher rig rates for deepwater have highlighted the need to reduce work stringtrips and time by using tools that are multi-functional, adding furthercomplexity.
Slickline-Retrievable Wellhead Plugs and Downhole Plugging System Provides Wellbore Integrity for Extreme HPHT Environments
Authors: Pickle Brad , Swan Tom 
Published: April 2012

Abstract
Trends in offshore exploration continually push the definition of high pressureand high temperature in regards to oil and gas well completions. Recentdiscoveries in the Gulf of Mexico (GOM) are opening up vast reserves of naturalgas and these discoveries are again challenging that definition. To meet theneed of high-pressure, high-temperature (HPHT) applications in general and foran operator in one such HPHT field, an ultra high-pressure and high-temperaturerated wellhead plug and downhole plugging system has been developed to providewellbore integrity in extreme conditions.
This paper addresses the challenges associated with development ofslickline-retrievable equipment rated to 25,000 psi at temperature extremesfrom 32°F to 450°F and the approaches used to overcome those challenges. Areview of design considerations, sealing technology, design verification, andvalidation testing that exceeds industry standards, is also provided.

Introduction
While the industry is rising to meet global demands for energy, the reservesneeded to fill that demand are increasingly in more challenging geologies suchas deeply buried reservoirs. Drilling to unprecedented depths is opening a newfrontier of pressure and temperature extremes. To appreciate the growth ofactivity in deeply buried reservoirs, according to the Energy InformationAgency, deep gas production in the US in 1999 was 7% of total production and in2010 an expected rise to 14% of US total gas production. In another industrystudy, the number of HPHT wells drilled from 1982 to 2010 was just over 300wells, while the forecast from 2011 to 2019 was to increase that total to over900 wells with a global geomarket distribution.
For many years, HPHT was commonly defined as 10,000 psi pressure and 300°Ftemperature or greater. The move into these new frontiers has moved beyond thetraditional definition of HPHT. One such classification structure is shown herein Table 1 with three levels of HPHT regimes. It is the move into the extremeand ultra HPHT regimes that is driving new methodologies of analysis andvalidation to ensure wellbore integrity in these very challengingenvironments.
As the scope of HPHT has expanded, the challenge facing the industry is how toprovide for wellbore integrity under such extreme conditions. This was thechallenge for one service provider to design and develop a wellbore pluggingsystem from the wellhead down to the bottom of the production tubing. To thisend, a unique landing nipple and slickline deployed plugging system wasdeveloped specifically for HPHT, capable of operating in all three regimes. Thenipple and plug system discussed in this paper was developed for a project inthe GOM and is rated to 25,000 psi and 450°F. The plugs incorporate a pumpthrough capability while also accepting a prong to convert to a positive plug. Key operational issues to minimize risks were also addressed.
Developing Process Safety Capabilities in New Engineering Graduates
Authors: Kim B.K. , Mentzer Ray , Mannan M.S. 
Published: April 2012

Abstract
Various major oil & gas incidents are constant reminders of the importanceand distinction between personnel and process safety. While the North Sea PiperAlpha disaster had a serious impact on both onshore and offshore operations, the more recent US Gulf of Mexico Deepwater Horizon incident has resulted innew regulatory requirements. The new Safety & Environmental ManagementSystem (SEMS) regulatory requirement emphasizes both process and personnelsafety aspects in Outer Continental Shelf (OCS) oil and gas operations. Whileprimarily a voluntary requirement since the mid-90's, effective November 2011, it has become mandatory. Consistent with industry's focus on process safety, training in process safety is now a mandatory requirement in ChemicalEngineering curricula starting in 2012. Academia has a significant role inimproving process safety and personnel safety by proving training and educationfor new engineering graduates, as well as the current workforce. In addition, advanced research programs can help close current gaps in the understanding ofprocess safety and ultimately improving safety performance of the OCS oil andgas operations. Such studies include safety culture, fires & explosions, facility layout optimization, inherently safer design, and pipeline corrosion, to name just a few areas.

1. Introduction
Process safety has become one of the inevitable elements in keeping businessesin various industries sustainable. Various industries have suffered painfullessons from incidents and have taken steps to prevent similar tragedies fromreoccurring. The Bhopal incident in 1984, which caused +2,000 fatalities, andthe more recent Deepwater Horizon incident, are a few examples which show thecatastrophic impact of process safety related incidents. Although eliminatingrisk entirely is not feasible, recent progress in process safety has improvedsafety performance through recognizing the risk and implementing safetymeasures to prevent or mitigate catastrophic consequences. This paper describesthe implementation of process safety in the offshore oil & gas industry, the new regulatory requirements, and discusses the training of engineers andresearch to promote safer operations.

2. Process Safety in Offshore Oil & Gas Industry

2.1 Development of Process Safety
The worst chemical disaster, the Bhopal MIC release in 1984, triggered newcomprehensive regulations in the US chemical industry [1]. Prior to the Bhopalincident, a systematic approach to understand the phenomena regarding processsafety had not been well established, but rather, case studies were conductedfor each incident. Following the Bhopal incident, the Emergency Planning andCommunity Right-to-Know Act (EPCRA) of 1986 was passed by the US Congress. ThisAct promotes emergency planning for potential chemical accidents and providescommunities with proper information on potential hazards imposed by thechemical processes [2].
Invited Organization: Marine Electromagnetic Methods for Gas Hydrate Characterization
Authors: Weitemeyer Karen Andrea , Constable Steven 
Published: April 2012

Motivation
Natural gas hydrates are a potential energy resource and a geohazard fordrilling and submarine infrastructure. Estimates of the global volume of gashydrate vary by over many orders of magnitude. Mapping the spatial distributionof gas hydrate deposits can be difficult using only seismic methods. Oneseismic signature is a bottom simulating reflector (BSR) which indicates thelower limit of the stability field, typically marking the gas hydrate to freegas boundary, but provides little information about the occurrence of gashydrate above it. Seismic blanking zones denote hydrate or gas only at shallowdepths below the seafloor. Another physical property of gas hydrate is that itis known to be much more resistive than seafloor host rocks. Recent laboratorymeasurements on unmixed CH4 hydrate (i.e. no sediment) confirms that hydrate isless conductive (10–5 to 10–4 S/m) than seawater (~ 10–1 to 101 S/m), providinga resistive target for marine controlled source electromagnetic methods (CSEM)(DuFrane et al., 2011). We have applied "standard" marine controlled-source EM(CSEM), and have been developing towed EM receivers to increase the density ofcoverage at fixed source-receiver offsets. A pilot study at HydrateRidge, offshore Oregon, illustrated our ability to distinguish between free gasbelow the seismic BSR (the edge of the hydrate stability field) and hydrateabove, and a more comprehensive study of 4 sites in the Gulf of Mexicodemonstrates our ability to image a variety of near-surface geology.