bluuebunny/crossref_metadata_2025_split huggingface dataset:
Improvements to Deepwater Subsea Measurements RPSEA Program: ROV-Assisted Measurement
Authors: Toskey Eric D. 
Published: April 2012

Abstract
This report documents a project to improve subsea flow measurements to allowthe flow rates of individual wells to be known more accurately, thus reducingrisk to both producers and the US government while also improving reservoirrecovery. In this project, a non-invasive metering approach was adopted using aclamp-on meter that may be conveyed to the sea floor using a ROV. The goal ofthis project was to develop and prove methods for conveying a clamp-on meter tothe sea floor by ROV, and document the results as a draft standard for thefuture. Meters/sensors were marinized for prototype demonstration in surfacemultiphase flow loops and in underwater test tanks.

1. Introduction
This paper presents the world's first subsea ROV-assisted clamp-on measurementsolution, and the industry factors and needs that have shaped its development.ROV-assisted measurement is the process of using an ROV in deep water to pickup a meter deployed to the seabed from surface, flying it to a meteringlocation, installing it on the pipe. After installation, measurements are madeon the fluids flowing in the pipe, and the data is sent to the surface inreal-time via the ROV umbilical. The meter can be flown to and installed atseveral metering locations before it is retrieved to the surface. The processof developing the technology is reviewed and the prototype meter that wasfabricated and tested is presented. The work presented here is the result ofTask 2 of the RPSEA DW1301 project, Improvements to Deep Water SubseaMeasurement, which has been presented in overview previously.1,2,3

1.1. Flow meter Verification.
All flow meters require some form of verification. Most conventionalsingle-phase flow measurements are verifiable because they are well-understoodmeasurements and they are accessible. For land-based or top-side flow meters, verification can be done by:Examining the condition of the flow meter itself,Examining the condition of the secondary devices and/or the quality of thosemeasurementsChecking the factory calibration or and re-calibrating the meter ifnecessaryVerifying the flow rate determination by checking the calculations using theequations programmed into the meter.Some meters offer diagnostic software to assist in evaluating the measurementquality and determining the need for re-calibration.
For meters employed in production allocation measurement, another commonapproach used to verify measurements is to compare the sum of individual flowstream measurements to the measurement of the combined stream. This approach, however, does not pinpoint measurement problems to the meter, and is affectedby other sources of error in rate determination when the flows are meteredperiodically instead of continuously.
Experimental Study of Air-Water Flow in Undulating Pipeline and Implication on Sand Transport
Authors: Osho Adeyemi Joseph , Yan Wei , Yeung Hoi Cheong 
Published: April 2012

Abstract
The study of multiphase flow is more difficult and complex in undulatingpipelines due to flow interaction between different pipe sections and influenceof the specific angles being studied. While previous studies (Zheng et al.,1995; Al-Safran et al., 2005) are low angles of hilly pipeline, there is noadequate information on flow characteristics for high angles. The complexity insand transportation in multiphase flow is more aggravated in undulatingpipeline
This paper presents experimental investigations to understand the multiphaseflow characteristics, conditions for slug initiation mechanism that wouldenhance sand transport in undulating pipes and assist pipeline design. Theinvestigations were conducted using a 2-inch (ID=50.24 mm) dip facility whichconsists of a downhill pipeline (−24o), a lower elbow (dip) and an uphillpipeline (+24o).
The slug initiation mechanisms phenomena were investigated. New flow regimeswere identified for different pipe sections using both visual observation andstatistical parameters. Sand transport characteristics in water and air-waterwere studied at different sand concentration. Also, flow condition to transportsand bed deposit at the dip was determined.
Three slug behaviours were observed at the dip: complete stratified flowdownhill with slug initiation at dip; stratified flow (with energetic ripple)downhill with slug initiation and slug growth at the dip; and aerated slugdownhill and slug growth at the dip. This behaviour is different from existingworks on this subject with low angle of inclination.

1. Introduction
Solid-liquid-gas flows are commonly encountered in industries such as chemicalprocessing plants, mining of coals and, oil and gas industry. It is apersistent problem in the petroleum industry for many years; most especially inpoorly consolidated reservoir or where hydrocarbon is in the increasing demand. It is quite impossible to produce a sand free hydrocarbon with presence of sandcontrol in place that can prevent sand production with the unprocessedhydrocarbon. However, the alternative approach is to transport sand along withthe multiphase flow hydrocarbon due to factors such as increase in demand ofhydrocarbon and cost to prevent sand production from the reservoir
Advances in Production Monitoring: A Deepwater Field Case History
Authors: Udofia Emmanuel E. , Van Den Berg Frans G. , Oguntimehin Adegbenro B. , Beijer Vincent , Cor Koster , Oni Olatunbosun 
Published: April 2012

Abstract
Bonga is a deepwater field, which lies 120km southwest of Warri in Nigeria at awater depth of 1000m. Bonga started production in November 2005 with sustainedwater injection for pressure maintenance and was the first deepwater project inNigeria. Production Universe which is a state-of-the-art Shell productionmonitoring tool was deployed as part of the Bonga Smart Field's FoundationMark-1 implementation and this has been used for real-time productionmonitoring and optimization. The Smart Fields Foundation project provides theBonga asset with accurate data and models for production surveillance andoptimization.
Real-time production surveillance and optimization has always been a challengeto efficient well and reservoir management in the oil and gas in industry. Conventional method of production monitoring in the oil and gas industry is toline a well through the test separator and acquire the required data. We thenerroneously assume that production from this well(s) remains constant(regardless of the prevailing situation affecting this well) during the periodof interest and we use this rate for monitoring. However, despite the complexnature of well testing in Bonga (with the support of a real-time ‘virtualmeter’ called Production Universe), we have been able to demonstratesignificant improvement in production monitoring and optimisation as shown inthe improved production reconciliation factor between estimated rates fromProduction Universe compared to the actual field production reconciled volumes. Bonga is a field with varying flow rates in the producer wells with very fastresponse to changes in water injection rates.
Hence, accurate production monitoring significantly improved the Bonga fieldWell and Reservoir Management process. The result could be applied to similarassets with the benefit of sustained real-time production monitoring.
Simulation of Slug Flow in Oil and Gas PIpelines Using a New Transient Simulator
Authors: Danielson Thomas John , Bansal Krishan M. , Djoric Biljana , Larrey Dominique , Johansen Stein Tore , De Leebeeck Angela , Kjolaas Jorn 
Published: April 2012

Abstract
LedaFlow® is a new transient multiphase flow simulator which includes 1Dmulti-fluid models consisting of mass, momentum and energy conservationequations for each field (continuous, bubble and droplet), as well ascompositional tracking. In this paper, a new method called Slug Capturing isemployed for slug flow, and the results analyzed and compared with the fielddata of two different fields. Additionally, for some cases, differences betweenthe new simulator and another commercially available transient code results arecompared and analyzed.
The first case corresponds to the production of a TOTAL-operated field in theUK. Produced fluids from the wells are transported through a 21 km long,16-inch multiphase flowline from the well platforms to the central receivingfacilities. The multiphase line (gas/oil/water) must be operated in a narrowrange of pressure and flow rate conditions in order to avoid severe sluggingissues. Flow patterns are compared for various water cuts and superficial gasvelocities. When severe slugging is observed, slug characteristics (frequency, length) are analyzed and compared to simulator predictions.
The second case is from a CONOCOPHILLIPS-operated North Sea asset. The 3-phase,18-inch ID oil flow line runs 3.7 km from a wellhead platform to a centralprocessing platform. The line drops approximately 6 m over the last 3 km beforeflowing up a 130 m riser. The pipeline exhibits severe riser slugging which isnot adequately modeled by conventional transient models, due to the complexinterplay between hydrodynamic and riser slugging, as well as 3-phase effects. Slug frequencies and lengths are analyzed and compared to predictions.

Background

The LedaFlow 1D Model
In this paper, the LedaFlow® 1D Slug Capturing model has been used to simulatethe field cases. The 1D model employs a three-fluid-nine-field modeling conceptto simulate the thermo- and hydrodynamics of the gas-oil-water three-phase flowin pipeline systems. In this approach, the various phases are assumed to flowin continuous zones and in the form of dispersed droplets within another zone. For instance, oil is transported in the form of continuous oil, oil droplets inthe water zone, and oil droplets in the gas zone. In a three-phase situation, the flow generally consists of three zones and nine fields. The momentum andenergy conservation equations are solved for each of the three zones, while themass equation is solved for all nine fields, yielding 15 conservation equationsaltogether.
Design and Development Considerations for HPHT Subsurface Safety Valves
Authors: Thompson Grant , Patterson Richard , Sloan James 
Published: April 2012

Abstract
Advances in drilling and completion technology are allowing high-pressure, high-temperature (HP/HT) applications to become more commercially viable. Whilethere is a minimum industry accepted designation of 15,000 psi as " highpressure" and 350°F as " high temperature," these are rapidly becoming the lowerlimits of the HP/HT category. The HP/HT designation serves to alert operatorsand manufacturers alike that equipment for such use requires a higher level ofattention to adhere to new regulatory requirements with respect to design, qualification, and testing.
While the HP/HT designation typically applies to all completion equipment ratedhigher than 15,000 psi or 350°F, it is particularly critical within thesubsurface safety valve suite of tools. As these tools serve as the emergencyfail-safe flow controlling safety device within the completion, they have asupreme requirement for both performance and reliability. These tools mustperform throughout the life of the well, which is extremely challenging whenoperating these tools in HP/HT environments. For such a development, everyfeature within the subsurface safety valve must be evaluated and scrutinizedand considered against regulatory requirements. As a result, additionalvalidation techniques must be employed to ensure robust, fit-for-purposeperformance of the product early in the development process.
This paper discusses key aspects in the design, development, and validation ofHP/HT subsurface safety valves. The paper will cover specific componentsincluding detailed stress analysis in addition to elastic displacements, metallic and nonmetallic materials, control fluids, and validationmethods.

Introduction
Driven by increased energy demands and the search for hydrocarbons in deeperformations, the number of HP/HT projects has increased significantly over thepast couple of decades. Advances in drilling and completion technologies allowfor extreme HP/HT applications to be commercially viable. And increasedcustomer collaboration with key operators, combined with significant investmentby service companies in technology innovation, will commercialize products thatwill make ultra HP/HT a reality in the not-too-distant future.
While there is a minimum industry accepted designation of 15,000 psi as" high-pressure" and 350°F as " high temperature," these are rapidly becoming thelower limits of the HP/HT category. The industry has widely accepted a tierstructure to depict HP/HT applications which categorizes these tiers andprovides detail to the limitations of completion technology within each (Fig. 1).
Phased Array Automated Ultrasonic Testing (PA AUT) Pre-Qualification
Authors: Widener Troy Andrew , Kan Wan , Wang Howard , Sutherland Jim , Monahan Craig C. 
Published: April 2012

Abstract
Industry of automated ultrasonic testing (AUT) has advanced significantly sinceExxonMobil last conducted a pre-qualification exercise to test capabilities. Therefore, it was prudent that ExxonMobil test the ability of these systems aspotential for their use increased on upcoming projects. In accordance withExxonMobil's global practices, and cooperation across multiple disciplines, this program achieved the result set forth: To test the viability of PhasedArray (PA) technology in the area of fatigue sensitive riser weldapplications.

Introduction
For previous ExxonMobil riser projects, there were limited number of qualifiedvendors and technologies to be used for automated ultrasonic testing (AUT)inspection of carbon steel riser welds. Due to the strict performancerequirements of the welds in riser applications, the allowable defect sizes arevery small when compared to pipeline acceptance criteria. To ensure riserintegrity, specific projects will perform an engineering criticality assessment(ECA) to determine the maximum allowable defect size that will yield acceptablefatigue performance and design life for the given application. From this, anacceptance criteria is created that factors in the height and length ofdefects, usually determined by some level of fatigue testing. Any nondestructive examination (NDE) method will also have its inherent tolerances anderror, so this also must be factored into the acceptance criteria.
The need exists to add flexibility to future ExxonMobil projects by expandingthis capability to include additional vendors and newer technology. ExxonMobilDevelopment Company, which is in charge of the development of capital projects, conducted a technology program to address this deficiency, by attempting topre-qualify multiple vendors with their latest technology, Phased Array (PA)AUT. Phased Array enables use of a single probe to send ultrasonic waves atmultiple angles, achieving the same results that would take multipleconventional ultrasonic probes to deliver.
Fundamentally, the physics of ultrasonics is no different between conventionalpulse echo and PA. The difference is that a PA probe is able to control theangle of incidence electronically. Digital beam angle adjustments are made inthe horizontal and vertical directions as appropriate to the geometry of theitem to be inspected (e.g., orientation of welds to be examined relative toprobe). The ability to alter beam angles electronically makes it possible toreplace several conventional probes with one phased array probe. In addition toimproved versatility, this approach reduces equipment set-up/maintenancerequirements and results in a more compact design. An example of a conventionalsystem is shown in Figure 1 below.
New Marine Era for Gas
Authors: Hatley John F. 
Published: April 2012

Abstract
The paradigm shift toward natural gas as a preferred fuel for marine offshoresupport vessels (OSV) and platform support vessels (PSV) represents a newmarine era. This paper examines five key trends driving this change; how thetwo shale gas phenomena of availability plus affordability combine with threeEnvironmental Protection Agency (EPA) mandates that together make a compellingcase for adoption of natural gas as a fuel.

Introduction
Earlier this decade the widely held belief was that expansion of natural gaswould arise by increasing imports of LNG into the US thus causing furtherdependence on foreign energy sources. Then came the vast shale gas discoveriesdomestically within the US and Canada as illustrated in figure 1. Within thispast few years a true transformation of the energy equation was aided by threestep advances; profound advances in computer capability aiding detectionefforts, efficiency advances from new horizontal drilling techniques, andhydraulic fracturing " fracing" technology for improved recovery. These elementsand an industry keen to develop such domestic resources have vaulted shale gasfrom 1% of US natural gas supply nearly 30% by the end of 2011, it continuesclimbing, and is projected now to provide nearly a century of supply. Adefinitive long term fundamental transformation has occurred that providesstrong stabilization to the North America market for many future generations. Current estimates position recoverable natural gas as exceeding 2,214 trillioncubic feet (TCF), a value which includes recent modest downward revisions bythe U.S. Energy Information Administration. Shale gas growth offsets other U.S.supply declines while meeting consumpation growth and nearly eliminates needsfor importation of LNG.
Nominal vs. Manufactured Chain Link Dimensions and the Implications on In-Service Inspection
Authors: Forbes Jim , De Gier Tyler 
Published: April 2012

Abstract
Requirements for both manufacture of chain links and in-service discardcriteria for inspection are well established by industry standards. Howeverstandards for discard criteria do not take into account one key element of themanufacturing process: the bending of round barstock around a form. Thiselement of manufacturing typically decreases the link diameter at the crown inthe axial direction, while potentially increasing the diameter in theperpendicular direction. When the axial crown diameter of in-service chains ismeasured, the discrepancy between the original manufacturing bar stock diameterand the in-service measurement values can lead operators to believe theirmooring systems are experiencing higher wear-corrosion rates than wereaccounted for in design.
To meet standards, the bar stock diameter of new chain links must be abovenominal diameter in all regions except the crown in the intergrip region. Aslong as the average of the two diameters within the link crown, axial andperpendicular, is at or above nominal diameter, the diameter at the crown maybe decreased by certain amounts, as defined by DNV and API.
Issues arise during time of in-service inspection because the axial diameter atthe crown is only accurately measured when there is tension on the chain. Theend-of-life discard criteria for chain links is based on nominal barstockdimensions, and does not take into account the axial crown diameter reductionthat occurs during manufacturing.
DNV and Lloyds Register both define chain discard criteria, for permanentlyinstalled mooring systems, as a 2% diameter reduction based on end of lifebreaking strength. The end of life breaking strength equates to the nominaldiameter (Dnom) minus the corrosion allowance (CA) built into the design. Basedon this definition, it is possible for newly manufactured chain to beapproaching in-service discard criteria before being used at all.
The discrepancy in nominal verses actual crown diameter should be determined bymeans of a baseline inspection prior to installation. Otherwise, following thefirst class survey at 5 years, asset owners/operators may believe that thecorrosion rate on the mooring system is in excess of 1mm/year, and that thechain will need to be replaced.
Welaptega has performed many in-service chain measurement surveys yieldingresults similar to the situation described above. As a result, Welaptega hasbeen informing the industry of the importance of pre/post-installation baselineinspection surveys to determine the actual chain dimensions, link length andaxial crown diameter and subsequently corrosion/wear rates present.
Using 3D Subsea Inspection Technologies for Pipeline Incident Response
Authors: MacCormick Marie , Hall Anthony David 
Published: April 2012

Abstract
Lack of preparedness in subsea pipeline incident response following unexpecteddamage results in delays in bringing a pipeline back into operation. Methodsfor identification, investigation, evaluation and assessment; and subsequentrepair can be pre-arranged to enable efficient response to damage events.
This paper presents two subsea inspection technologies that enable operators toperform routine pipeline surveys, and investigate, quantify, analyse, andrepair pipeline damage:

High Definition 3D Video
Welaptega's recently developed high definition 3D video camera system isdeployed by ROV to capture high definition stereoscopic video footage, enablingoperators to identify damage such as gouges and pitting during real-timeinspection.
The HD3DV system can be deployed to perform routine inspections and to capturedetailed 3D footage of damage locations to fulfill the requirements foridentification and investigation in pipeline incident response.

Photogrammetric 3D Modelling
3DModelling uses advanced photogrammetric techniques to generate geometricallyaccurate 3D models of components from 2D digital still images. Matching pixelsare identified between overlapping photos, and geometry is calculated through aseries of iterations based on the pixels' relative positions. 3D models arescaled with respect to the known offset between cameras or an object of knowndimensions placed on the component.
Resulting 3D models represent particular pipeline geometry and can be measuredto quantify critical dimensions such as pipeline curvature, cross-sectionalareas, and gouge depths, widths, and heights. 3D models can also be exported informats compatible with finite element method software packages forstress/strain analysis. If a clamp is required for pipeline repair, the 3Dmodel can be exported to industry-standard CAD (computer-aided design) packagesso that a custom design can be fitted to the damaged pipeline geometry.
The above methods are completely non-destructive in nature, and require minimalpreparation work to the target area prior to data collection. The resultsrepresent the highest degree of accuracy achievable of any underwaterinspection technology that is non-invasive and flexible enough to work in avariety of locations and operating environments.