bluuebunny/crossref_metadata_2025 huggingface dataset:
Improvements to Deepwater Subsea Measurements RPSEA Program: Evaluation of Flow Modelling
Authors: Toskey Eric D.
Published: April 2012

This report documents a project to improve subsea flow measurements to allowthe flow rates of individual wells to be known more accurately. Becauseproduction revenues are determined from flow rates, improved flow measurementreduces the financial risk to stakeholders, including producers and the U.S.government. Improved measurement also helps to improve reservoir recovery. Inthis project, commercially available flow models were evaluated for theirsuitability as virtual flow meters, to augment or replace hardware devices forthe determination of flow rates in deep water wells. The goal of this projectwas to develop methods for evaluating flow models, and to report on theefficacy of these models to predict flow rates. Several flow models were usedin the study, which also includes a survey of the available models.

1. Introduction

1.1. What is a Virtual Flow Meter?

Virtual flow meters (VFM) are a method for determining the flow rate of a wellby means of modeling the flow. A VFM model may consist of a single well to anentire field of co-mingled wells. The models are fed data from sensorsinstalled at various measurement points (nodes). Typically pressure andtemperature sensors are used, which are available downhole (perhaps at multiplepoints), at the wellhead, and at the surface. With the pressure and temperaturedata at each node provided as an input, the VFM model computes the flow rate ofthe well. Typically, the model is tuned periodically using available flow data. Once tuned, the model is capable of determining the well flow rate with onlythe pressure and temperature nodal data. The flow models employed with VFMsystems may be built from first principles, but this is not the only method forVFM modeling. Flow models may also be derived from statistical analysis ofmeasurements acquired at different nodes along the production system.

An important observation is that VFM software is not something that must beinstalled at the same time as the physical multiphase flow meters, as long ascare is taken to install proper sensors to be used at the various nodes. Thefault tolerant nature of the VFM system is an advantage, since a failed "hard"sensor will reduce the number of nodes, but will not cause a complete loss ofinformation.

While VFM technology appears to be maturing rapidly, it is not yet generallyaccepted an equivalent replacement for good physical metering. VFM models areemployed as a back up to a physical meter to be used in case the primarymetering system is unable to function, or as an augmentation of physicalmetering to reduce measurement uncertainty.

Some of the commercial VFMs use the technique of Nodal Analysis for the flowrate prediction. This method utilizes available transmitters (pressure andtemperature) and a mathematical model of the complete flow path from bottomhole to the topside facility. This method requires considerable input data, including well and pipeline profiles, the diameters of all components ofsections, sensor locations, fluid properties, choke geometry, etc.
Improvements to Deepwater Subsea Measurements RPSEA Program: ROV-Assisted Measurement
Authors: Toskey Eric D.
Published: April 2012

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

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

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

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

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

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

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

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

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.
Foundation Modeling and Assessment in the New ISO Standard 19905-1
Authors: Wong Patrick C. , Templeton Jack , Purwana Okky Ahmad , Hugo Hofstede , Cassidy Mark Jason , Hossain Muhammad Shazzad , Martin Chris
Published: April 2012

This paper presents the new foundation assessment provisions in ISO 19905-1. The paper discusses the improvements to spudcan penetration analysis achievedby the refinement of bearing capacity formulations and by adoption of afundamentally new approach to backflow prediction which accounts for thechanges in soil flow regime and the evolving pattern of soil deformation in thevicinity of the spudcan. It also addresses the upgrades made to the SNAME 5-5Aapproach to foundation capacity and foundation stiffness reduction in sand andclay as well as the means used to better account for the effects of deepspudcan penetrations in clay. The change to, and basis for, the use of grossfoundation capacity in some of the calculations are also discussed. Finally, the paper presents the new foundation acceptance checks framework consequent tothe change from available capacity/reaction concept in SNAME 5-5A to grosscapacity/reaction approach in ISO 19905-1.

At the time of this paper submission, it was expected that ISO 19905-1 would beisssued prior to the presentation of the paper at the 2012 Offshore TechnologyConference. Upon the issue of this standard the new foundation assessmentprovisions described in this paper will be required for jack-up site-specificassessments worldwide.

Introduction and Background

The jack-up geotechnical assessment approach in ISO 19905-1 is the result ofthe concerted effort of Panel 4 under the auspices of ISO TC67/SC7/WG7. Thedevelopment of the latest assessment approach by Panel 4, made up ofexperienced geotechnical practitioners in the industry and well-respectedresearchers in academia, spanned almost two decades. Using SNAME TR5-5ARevision 2 as the starting point, the geotechnical assessment approach wasrevised and upgraded based on findings from industry studies and academicresearch projects in understanding spudcan foundation behavior over theyears.

The prior and existing recommended practices for assessment of jack-upfoundations and their performance under storm loading conditions stemmed fromindustry studies in the 1980s and early 1990s. Those recommendations weresubstantially conservative by intention, and they were limited by the researchof the time. As a result they were reliable but, in many cases, overlyrestrictive for jack-up location approvals. Not only are the new foundationassessment requirements of ISO 19905-1 better grounded in current research, they are less restrictive and more realistic while remaining reliablyconservative. This paper provides an overview of five main geotechnical areasin the geotechnical assessment approach, namely:Site investigation requirementsSpudcan penetration and foundation bearing capacitySpudcan foundation response under combined load during stormSpecial spudcan foundation considerations (fatigue, earthquake)Spudcan foundation acceptance criteria
Reliability and Integrity Assurance of Subsea Technology using ASCE
Authors: Strutt John Edward , Emmet Luke , Cleland George
Published: April 2012

Aggressive schedules, high standards for integrated system performance andtight budgets increase the pressure on field development projects or technologydevelopment projects to deliver solutions with acceptable reliability andintegrity. In addition, the industry and government are challenged to respondadequately to the inherent risks to system integrity introduced by supply-chaincomplexity; operators, regulators and system integrators, suppliers both largeand small all need to interact seamlessly.

For subsea systems, the achievement of a high level of reliability andintegrity are key requirements and are of particular significance for equipmentwhere failure during operation has the potential to cause large adverse safetyor environmental consequences e.g. drilling operations (subsea BOP system) andproduction (HIPPS). Industry practices such as API RP 17N which recommends thesetting of goals and requirements, preparation of plans and the provision ofrisk and reliability assurances on reliability and integrity critical equipmentare gaining increasing support from Operators, Contractors, andRegulators.

A key question is how hardware, people and processes can be developed tosupport current industry programs and standards to support the widely felt needfor greater reliability and integrity assurance in the subsea industry. Anessential element of this is managing the complex information base supportingthis. The Assurance and Safety Case Environment (ASCE) system is a softwaresystem designed explicitly for this purpose. It is in widespread use in otherdomains such as defense, air traffic control, and nuclear. In this paper wedescribe the ASCE tool and its potential application in subsea projects, operations and drilling to support Operators, Drilling Contractors, and OEMsuppliers in provision of assurances and compliance with Government, Industryor Regulatory requirements.

Introduction

The global demand for hydrocarbons continues to increase year on year and withmost of the easily accessible land based reservoirs depleting, the search forhydrocarbons over the past 15 years, has shifted offshore, fuelling the growthof a global subsea industry. Many current and future hydrocarbon resources areto be found offshore and increasingly in deep water in environmentally andpolitically sensitive areas. In such areas any failure which results in loss ofcontainment or loss of well control is highly significant.
Insights into Using the 22nd Edition of API RP 2A Recommended Practice for Planning, Designing and Constructing Fixed Offshore Platforms - Working Stress Design
Authors: Digre Kris A. , Zwerneman Farrel
Published: April 2012

This paper provides insights and interpretations regarding the use of API RP2A-WSD 22nd Edition. In 2010, OTC paper #20837 discussed modifications beingmade to and reasons behind the changes to API 2A-WSD in conjunction with othernew API standards, 2MET, 2EQ, 2SIM and 2GEO and the elimination of APIBulletins 2INT-MET, 2INT-DG and 2INT-EX. In this paper, emphasis is placed onuse of the 22nd Edition in combination with the other new standards.

General

API RP 2A-WSD 22nd Edition was balloted in 2011 and approved by 96% of thevotes cast. There were over 339 individual comments (the vast majorityeditorial) with some 21 still in final resolution by API TG13 at the time thispaper was written. This has resulted in the API RP 2A-WSD 22nd Edition finaltable of contents to include the following (with reference to the 21st EditionSection in parentheses):Section 1: ScopeSection 2: Normative ReferencesSection 3: Terms, Definitions and AcronymsSection 4: Planning (21st Edition Section 1)Section 5: Design Criteria and Procedures (21st Edition Section 2)Section 6: Structural Steel Design (21st Edition Section 3)Section 7: Strength of Tubular Joints (21st Edition Section 4)Section 8: Fatigue (21st Edition Section 5)Section 9: Foundation Design (21st Edition Section 6)Section 10: Other Structural Components and Systems (21st Edition Section7)Section 11: Material (21st Edition Section 8)Section 12: Drawings and Specifications (21st Edition Section 9)Section 13: Welding (21st Edition Section 10)Section 14: Fabrication (21st Edition Section 11)Section 15: Installation (21st Edition Section 12)Section 16: Inspection (21st Edition Section 13)Section 17: Accidental Loading (21st Edition Section 18)Section 18: Reuse (21st Edition Section 15)Section 19: Minimum and Special Structures (21st Edition Section 16)Annex A (Informative): API 2A-WSD 21st Edition vs. 22nd EditionCross-referenceAnnex B (Informative): CommentaryBibliography

Changes from OTC paper #20837 and specific topics of importance in using thenew API Standards are discussed below.
15K plus, The Limits of Established Pressure Vessel Design Methods
Authors: McKie Nigel , Skeels Brian , Williams Michael R. , Marotta Egidio , Peters Dan
Published: April 2012

The majority of oilfield pressure containing Wellhead and Tree equipment hasbeen designed with guidance from API 6A and 17D. However, their design methodsare not the most appropriate for High Pressure High Temperature (HPHT)applications. This paper discusses the limitations of established PressureVessel design methods and presents more suitable methods for HPHT.

Unfortunately, these methods are not readily intuitive or straightforward. Sothis paper also addresses the challenges currently being faced by designers ofHPHT oilfield equipment. Recent design evaluations of HPHT equipment haverevealed significantly different (and sometimes unexpected) results from thevarious design and analysis methods that are available. Several industrystandard design and analysis methods are discussed and compared, using simpleHPHT equipment geometries to illustrate the authors' findings. Although work isstill in process, this paper shares some significant findings that should berecognized and understood by HPHT equipment designers in order to ensure thattheir design methods are appropriate for the application. In conclusion, on thebasis of these findings the authors determined that many of the established andcommonly used oilfield methods of Pressure Vessel design are not the mostappropriate for HPHT applications. They are not accurate for thick-walledcomponents and their use is open to interpretation. Thus, it is recommendedthat designers carefully review and understand their design methods to ensurethat they are accurately predicting the stresses, deflections and fatigue lifeof the equipment under development.

Introduction

As exploration for oil and gas has moved into deeper, hotter and higherpressure zones, the design and stress analysis for oilfield equipment becomesever more critical and challenging. The higher pressures, and therefore thickerwall sections, mean the thin-wall assumptions of the past are no longer valid. Historically, designers could overdesign the equipment to provide a robustproduct with liberal Design Margins. However, for the newer HPHT oilfieldequipment, there is literally no room for overdesigned equipment and with thefailure mode shifting towards fatigue and fast fracture, very accurate andrealistic stress analysis and design methods are essential to achieve safe, reliable and cost effective equipment designs.

Another aspect critical to HPHT design are the relative movement betweencomponents and stress relaxation phenomenon for seals and their sealinglocations. But this subject is beyond the scope of this paper, focusing insteadon pressure vessel design requirements.
Electric Heating of Pipelines and Large Export Flowlines > 30" and more than 100 km
Authors: Heggdal Ole , Pedersen Atle , Lervik Jens Kristian , Bjerknes Ole-Johan
Published: April 2012

Direct electric heating (DEH) of long flowlines and large export pipelinesprovides many advantages compared to alternative methods. DEH has been appliedactively in the past 10 years to prevent hydrate formation and is now breakingnew ground that was not previously considered feasible. By using qualifiedtechnology and existing design models, longer and larger pipelines can beheated intermittently or continuously.

Electric heating of pipelines is attractive for long step outs greater than 100km, as DEH running costs are considerably reduced compared to the use ofchemicals. The technology is unique and commercially and technicallyattractive. It allows for the use of DEH for both infield flowlines and exportpipelines of 30" and above. An increased number of DEH systems have beenevaluated for oil and gas field project developments on continental shelvesaround the world, and the extension of this new technology will give higherflexibility in operation of the fields during planned or unplanned shut downs. Material aging and other failure mechanisms caused by high temperatures andwater pressure are also of great importance. Accuracy in design and analysis aswell as industry experience are important in solving project specific hydrateor wax issues in long DEH systems.

The system is easy to install and operate and has low CAPEX and OPEX costs. Anew cable design and installation method has improved the robustness of theoverall system and makes the system more compatible with large and heavy pipeson the seabed. New condition monitoring also secures optimal heat input andimproves service-life.

Complete heating systems for large export pipelines, with power supply fromshore, are available within the industry.

Abbreviations

DEH - direct electrical heating.

DEHC - direct electrical heating cable (cable piggybacked to thepipeline).

DEHS - direct electrical heating system.

CWC - concrete weight coating.

CTZ - current transfer zone.
Analysis of Salt Creep and Well Casing Damage in High Pressure and High Temperature Environments
Authors: Lao Khang , Bruno Michael S. , Serajian Vahid
Published: April 2012

Drilling and completing wells through deep thick salt formations is technicallychallenging and costly. Salt material flows over time whenever a stressdifference, or shear stress, is induced. The rate of deformation primarilydepends on the stress difference, and on the temperature. Both of these factorsincrease with increasing depth, often leading to severe loading and deformationof wells, and sometimes severe damage and loss of functionality. Geomechanicalanalysis can be applied to estimate such loading, to estimate damage risks, andto optimize well designs for these challenging conditions. We describe herein aprocess to evaluate salt creep and casing damage risk for high pressure andhigh temperature conditions typically encountered in deep salt formations. Because well costs often exceed 50 million dollars each, appropriate welldesign and risk analysis, supported by geomechanical modeling of salt andcasing behavior, is critical to project economics.

To simulate the visco-elasto-plastic behavior of salt, we apply thetime-dependent constitutive framework available in FLAC3D. The availableformulation is modified by Terralog to account for damage accumulation duringprimary loading, associated strength degradation, compaction-dilationtransition based on the Drucker-Prager yield criterion, and loading-unloadingresponse.

We provide an illustrative example for a deepwater Gulf of Mexico field, inwhich a multi-string casing-in-casing design was considered to resist long-termcreep. Laboratory creep data was used to calibrate the constitutive model, which was then applied to a near wellbore scale geomechanical model thatincluded the casing strings, cement, mud pressure, and 10ft of surroundingsalt. The simulation results indicate that the for the design configurationsconsidered, the minimum time for salt to contact the outer casing was on theorder of 2 years for the most severe scenarios (lowest annulus pressure), andmore than 20 years for the strongest configurations. Geomechanical analysis ofthis type provides a relatively low cost approach to quantify casing damagerisks and to optimize casing designs for completions in high stress and hightemperature environments.

Introduction

Increasing exploration and production from deep regions around the worldrequire drilling through and completing wells in thick salt formations, leadingto very high well costs. Appropriate designs are required to withstand creepinduced loads during drilling and after completion. The introduction of awellbore in a salt formation changes the existing local stress field, inducinga stress difference between the borehole and surrounding salt, and resultingtime-dependent (creep) loading on well casings. Production of hot fluids fromsubsalt formations adds additional thermal strains to the wellbore andthermally induced creep acceleration.
Global Energy Outlook: Changing Patterns
Authors: Hassan Gamal A. , Hashmi Ahmed , Al Zanki Farouk , de Azevedo Jose Gabrielli , de Castro Sergio Martinez , Eyton David , Bichsel Matthias , Moshiri Ali , Mathieson Derek
Published: April 2012

It is now widely recognized that the world has sufficient oil and gas resourcesto satisfy future demand. However, there are also acknowledged uncertainties inthe provision of this supply to meet future energy needs as investors faceseveral risks, in an industry with long lead times and long pay-back periods. The ongoing impacts of financial turmoil and economic downturn, the changingstructure of world energy markets, and developments in policies andtechnologies all directly affect energy supply and demand.

In addition, the emergence of oil as an asset class has transformed the oilmarket, which is now far more exposed to the broader financial markets. As aresult, the oil market has experienced greater volatility and the price ofcrude has been impacted by a growing number of factors that are not directlyrelated to supply and demand fundamentals.

This panel will debate key issues affecting today's fast-changing global energyindustry. It will examine the challenges and opportunities facing the petroleumsector, and seek to identify potential 'game-changers' in technologies andpublic policy.

The panle will address:

Global trends

– What are the global trends that will drive the world's economies and energydemand over the next 20-30 years? – What structural shifts have taken place in energy demand (global as well asregional) and energy supply patterns over the past few years?

Role of Oil and Gas

– How do oil and gas investments interact with developments in the worldeconomy - lessons learned from the recent economic and financial crises and theimpact of the global business cycles? – What is the role of oil and gas in meeting future energy demand?

Role of Technology

– What are the most promising technology innovations on the horizon for the oiland gas industry? – What are the most disruptive technology innovations that could affect futuredemand for oil and gas? What is their time frame?

Role of Policy

– What are the examples where policy has been successful or unsuccessful? Whatcan we learn from these examples?
Deepwater Cementing Standards: Applicability and Regulatory Impact of Best Practices
Authors: Mueller Dan T.
Published: April 2012

Cementing subject matter experts serving the API Task Group on RP 65, APISubcommittee 10 on Well Cements and its international counterpart, ISOTC67/SC3/WG2, have worked collaboratively for over a decade to produce a seriesof best practices related to various elements of deepwater well construction. The relevant standards produced by the organizations include:API RP 65: Cementing Shallow Water Flow Zones in Deep Water Wells(2002)API RP 65-2 (First Edition): Isolating Potential Flow Zones during WellConstruction (2010)

API RP 65-2 (First Edition) was superseded in December, 2010 by:API Standard 65-2 (Second Edition): Isolating Potential Flow Zones duringWell Construction (2010)API RP 10B-3 (ISO 10426-3): Testing of Deepwater Cement Formulations(2003)API RP 10B-4 (ISO 10426-4): Atmospheric Preparation and Testing of FoamedCement Slurries (2004)

As a part of the industry and regulatory response tothe Deepwater Horizon disaster, a newfound focus is being placed on the design, testing and placement of cement slurries used in deepwater wells. This paperwill outline the areas of applicability, revision status and regulatory impactof the standards and recommended practices which are now guiding the wellcementing industry in the post-Macondo era.
Incorporation of Multi-Member Substructure Capabilities in FAST for Analysis of Offshore Wind Turbines
Authors: Song Huimin , Robertson Amy , Jonkman Jason , Sewell DeAnna
Published: April 2012

The Fatigue, Aerodynamics, Structures, and Turbulence (FAST) code, developed bythe National Renewable Energy Laboratory (NREL), is an aero-hydro-servo-elastictool widely used for analyzing onshore and offshore wind turbines. This paperdiscusses recent modifications made to FAST to enable the examination ofoffshore wind turbines with fixed-bottom, multi-member support structures(which are commonly used in transitional-depth waters).

This paper addresses the methods used for incorporating the hydrostatic andhydrodynamic loading on multimember structures in FAST through its hydronamicloading module, HydroDyn. Modeling of the hydrodynamic loads was accomplishedthrough the incorporation of Morison and buoyancy loads on the supportstructures. Issues addressed include how to model loads at the joints ofintersecting members and on tapered and tilted members of the supportstructure.

Three example structures are modeled to test and verify the solutions generatedby the modifications to HydroDyn, including a monopile, tripod, and jacketstructure. Verification is achieved through comparison of the results to acomputational fluid dynamics (CFD)-derived solution using the commercialsoftware tool STAR-CCM+.

Introduction

Interest is growing in offshore wind turbines. Many offshore-wind-turbinesupport structures are being developed by modifying onshore wind turbinefoundations, or oil and gas (O&G) industry structures. The offshore windturbine support structures can be classified in three categories according tothe water depth, as shown in Figure 1. In shallow water, where the water depthis less than 30 meters, monopiles and gravity bases that extend to the seafloor are used. In transitional depth, where the water depth is between 30 and60 meters, new technologies are being created or adapted from the O&Gindustry, including jacket and multi-pile structures, which also extend to thesea floor. When the water depth is greater than 60 meters, a rigid structurefixed to the sea floor is no longer economical, and floating platforms may berequired. This paper is focused on analyzing the support structures intransitional water depths.