bluuebunny/crossref_metadata_2025 huggingface dataset:
Understanding the Effects of Deep-Sea Conditions on Seafloor Massive Sulfide Deposits Crushing Process
Authors: Waquet Benoit , Faulds Donald , benbia ali
Published: May 2011

Seafloor massive sulfide deposits provide a rich polymetaliferous ore including elements such as gold, silver, copper, etc. They can be found in oceanic volcanic zones at the seafloor.

The challenge is to extract this ore and raise it to the surface. The most promising technique consists of the following steps:Extracting the ore from the seafloorReduce the extracted ore down to sizes small enough for raising to the surface (crushing)Raising the crushed material to the surface.

Size reduction of the rocks by mechanical methods in atmospheric conditions is well understood. However, the effect of deep sea hydrostatic pressure on the mechanical rock crushing process is largely unknown, but will be critical for future subsea mining operations.

This paper describes a series of tests performed by Technip to observe and understand the effects of deep-sea conditions on rock crushing. A compact rock crushing unit, including a MMD 200 series sizer, was installed inside a large hyperbaric chamber. Tests were performed in atmospheric conditions and at several hydrostatic pressures up to 200 bar, in a highly controlled manner. The crushing process was video observed, crushing forces were measured in real-time, and resulting particle size distributions were analysed. Three different rock types with geotechnical properties relatively similar to massive sulfides deposits were processed namely, puzzolane, limestone and a formulated concrete. Rocks were water saturated before being tested to reproduce seafloor saturation conditions.

The results have clearly settled that deep-sea crushing requires more power than a classical terrestrial crushing. This statement will be critical for the developement of Technip seafloor crushing unit project.
Low Dosage Hydrate Inhibitors (LDHI): Advances and Developments in Flow Assurance Technology for Offshore Oil and Gas Productions
Authors: Tian Jun , Bailey Cheryl , Fontenot Jacques , Nicholson Michael
Published: May 2011

The last thing the offshore operators want to see is after all the investments in exploring, drilling and production, they could not flow the hydrocarbon from underground smoothly and efficiently. Among all the offshore flow assurance challenges, in a short time period can hydrate restrict flow and even form a solid plug to block all production. Long deepwater subsea tiebacks are especially problematic due to the high pressures and low temperatures, which would require sufficient quantities of thermodynamic hydrate inhibitors (THI) injection for hydrate mitigation. High THI injection volume can both exacerbate scaling problems by salting out of high TDS brines, and contaminate the exporting hydrocarbon by methanol. All these offshore production challenges, coupled with complicated logistics and HS&E concerns on THI, have being endorsed the development and field deployment of low-dosage hydrate inhibitors (LDHI) in the last decade.

Given the costs associated with remediating problems in offshore systems and the corresponding deferral of production, each new LDHI development is put through a series of rigorous qualification process. This paper will detail the challenges associated with LDHI applications for offshore productions. Efforts at developing and deploying new DLHI products suitable for number of recent offshore applications worldwide with field different requirements will be highlighted. Umbilical and capillary line failure is a major concern in the industry. Best practices to qualify products for umbilical and capillary injection have been rapidly evolving over the last ten years. Stability of LDHI formulations can depend on both temperature and pressure. In particular, high pressure viscometer measurements have proved to be invaluable for determining whether apparent pressure related stability concerns may exist in formulations at cold deepwater temperatures. Moreover, LDHI compatibilities with production fluids, system materials, other production chemicals and no adverse effect on their performance are also the key to its successful field implementation. Subsequently, closely monitored topside tests and field trials are essential to gain insights to the product performance in real systems.
Seafloor Production Tools for the Resources of the Future
Authors: Ridley Nick , Graham Simon , Kapusniak Stef
Published: May 2011

Soil Machine Dynamics (SMD) is one of the world's leading subsea engineering companies specialising in the design, manufacture, assembly and marinisation of equipment for the oil and gas, telecommunications, defence, scientific, renewable and mining sectors. The company has progressively developed since 1971, quickly gaining a reputation for supplying innovative equipment for the burial of pipelines and cables. In 2003, with the acquisition of Hydrovision, we entered the work-class ROV market. Further growth led to the recent acquisition of Hallin Robotics and an expansion from our deep-sea trenching skills base into seafloor mining equipment.

This paper focuses on the design of Seafloor Production Tools (SPT's) for Nautilus Minerals Inc.(NMI)'s Solwara 1 copper/gold deposits in the Bismarck Sea, off Papua New Guinea. The design solutions adopted are described, highlighting advances and adaptations to existing mining and dredging technology. In particular, the paper focuses on the solutions developed to overcome challenges relating to;specific operating conditions in the Bismarck Sea,marinisation of heavy duty mining equipment for deep-sea operation,remote control of machines and pilot interfaces,interfaces with Nautilus' Production Support Vessel (PSV) and Subsea Lifting Pumps (SSLP).

This project is undoubtedly one of the most exciting offshore engineering projects currently being undertaken. There has been keen interest from subsea, mining and dredging component suppliers and a high level of cross-industry cooperation since the start of the project. The technology described will help encourage subsea mining companies to seek out new deposits and cross resource frontiers that were hitherto considered as inaccessible.

Introduction

As economic surface resources are gradually depleted, the search for replacement mineral commodities is shifting towards new environments. SMD's client, Nautilus Minerals Inc. is a pioneer in the exploration of the seafloor to find economically attractive massive sulphide deposits. As Nautilus's exploration programme releases more geological and geotechnical detail and mining plans become firmer, the design of tools to exploit the sulphide deposits is being refined. Material strengths- accounting for estimates of hyperbaric effects- are within the bounds of the strength of materials already excavated by subsea Rock Trenchers previously designed and built by SMD, such as " RT1??.
Three Wind Turbines On One Floating Unit, Feasibility, Design And Cost
Authors: Lefranc Marc , Torud Anders
Published: May 2011

The paper presents results from the design work and the model tests [1] performed to verify the feasibility of a new offshore floating wind concept with three turbines on one platform. The economics of the concept is also discussed.

The platform is a semi-submersible with three columns shaped in a regular triangular supporting three turbines, two turbines in front (up wind) and one turbine in the rear (down wind). This geometry challenges the established state of the art since one of the three turbines is located in the wake of the two other at a distance of one rotor diameter. The platform is anchored through a " turret?? at its geometrical centre. This enables the platform to rotate in to the wind at all times.

One major issue is the wake effect produced by the two upwind turbines on the downwind turbine. This aspect has been addressed by CFD analysis and verified by model tests in wind tunnel.

Interaction between motions due to wave and wind action has been evaluated based on computer simulation and tested on scaled model in wave basin.

Based on the data collected in the model tests, a concept supporting three turbines of 3,6 MW has been sized for a location in the southern part of the North Sea. The cost for fabrication and installation has also been estimated as well as the annual energy production based on specific wind data.

The production loss on the rear turbine caused by shadowing effect from the front turbines has been verified to be only 25% of theoretical maximum production. This is a significant finding because the loss is by many industry experts expected to be much higher. The up wind turbines experience no loss due to interference between the turbines.

Based on these findings the cost of production per kwh has been estimated. Results will be presented in the paper.

Following the verification described in the paper the platform concept will be optimised and subsequently detail engineering, construction and testing of a full scale prototype will be carried out.
Reelable Cost Effective and Enabling PipelineTechnologies
Authors: Denniel Sylvain , Tkaczyk Tomasz , Smith Daniel
Published: May 2011

Over the past year, Technip completed the qualification of two cost effective products for reeling installation. These are mechanically lined pipes (lined pipes) and optimized wall thickness High Frequency Induction (HFI) pipes. Separate successful qualification programs including numerical analyses, full scale and small scale testing were undertaken.

Mechanically lined pipe is a very cost effective alternative to solid stainless or metallurgically clad pipelines for the transportation of increasingly corrosive fluids, which is a strongly growing trend. Such product was installed by S-lay in the past and there has been an incentive to qualify it for the very efficient reeling installation method. A number of critical control parameters enabling maintenance of liner integrity throughout the reeling process have been identified. A lined pipe design that can be reeled at atmospheric pressure without compromising the integrity of the liner has been qualified.

HFI pipelines are commercially more attractive than the commonly used seamless pipelines. However, some aspects of the HFI pipe technical specifications are not readily adapted to design optimized wall thickness pipelines for reel-lay installation. This paper addresses the resolution of the wall thickness selection of such pipes, for designs governed by reeling. The qualification program provided the justification for using optimized HFI pipe wall thickness for reeling in current projects.

Both HFI and lined pipeline products offer significant procurement cost savings to a project. Each technology has reached a qualification maturity, which has led to project applications for some. These products could be combined within a single very cost effective pipe-in-pipe design for challenging flow assurance conditions, in terms of corrosion resistance and wax/hydrate avoidance.

Introduction

Many field developments combine the challenges of high passive insulation demands and needs to transport highly corrosive products under high temperature and pressure conditions. A typical solution meeting such technical requirements would be a low Overall Heat Transfer Coefficient (OHTC) reeled pipe-in-pipe (PiP), inclusive of a solid Corrosion Resistant Alloy (CRA) inner pipe. The outer pipe (also called carrier pipe) would typically be a seamless carbon steel pipe, whereas expensive stainless steel materials, such as 13%Cr martensitic steel, 22%Cr Duplex or even 25%Cr Super Duplex would be considered for the CRA inner flowline.

Technip has recently been able to propose a cheaper reeled PiP solution by introducing two cost attractive pipeline products, which have been qualified for reeling. These are optimized wall thickness HFI carbon steel pipes (instead of seamless pipe) for the carrier pipe and mechanically lined pipe for the inner flowline.
TTS - The Systematic and Efficient Approach to Define, Maintain and Demonstrate Safety Performance on Complex Hydrocarbon Processing Facilities
Authors: Firing Frank L. , Ostby Erik , Ingvarson Johan , Strom Oyvind
Published: May 2011

Authority regulators as well as shareholders, the public and other stakeholders require owners and operators to demonstrate the safety performance of their processing facilities. A particular focus is put on safety barriers managing major accidents with the potential of causing severe fatalities and long-lasting damage to the environment. Statoil has implemented a structured approach for assessing the condition of the safety barriers on their processing facilities as a key measure to control and reduce major accident risk. Performance Standards (PS's) are defined for each barrier and each PS defines a set of Performance Requirements (PR's) to be met by that particular system with respect to system function, integrity, survivability and management respectively. The set of PR's incorporates regulatory and internal requirements based on best industry practice. A comprehensive assessment program, incorporating a detailed grading system, regularly reviews compliance with the PR's and assigns a common grading.

The TTS process focuses on a systematic assessment of the actual technical integrity and condition of process safety barriers implemented in facilities in operation, as well as facilities under design and construction. TTS provides a powerful approach to:Measure and ensure safety performancePrioritize corrective actions and major accident hazard risk management improvement initiativesBuild process safety awareness and competenceDemonstrate regulatory compliance.

Introduction and Background

Managing major accident risks on complex hydrocarbon processing facilities is an ongoing challenge. The TTS process for structured evaluation of technical safety systems or barriers at operating facilities have been developed over a number of years. Initially, a process for systematic and structured evaluation of technical safety systems in operation was developed by Statoil in 2000. The process was named TTS - Teknisk Tilstand Sikkerhet (Norwegian for technical condition safety) and focused on a systematic assessment of the technical integrity and conditions of the existing process safety barriers. DNV was engaged to provide support in Statoil's roll-out and implementation of the TTS process.

Following successful implementation at Statoil facilities, Norsk Hydro showed interest and implemented a similar approach at their facilities with Statoil's consent. The TST (Teknisk Sikkerhetstilstand) process was launched in Hydro in 2003. Following the merger between Statoil and Norsk Hydro Oil & Gas business, Statoil is still applying the process under the name TTS, which in fact combines the best practices of the former two companies.
Using Tomographic Seismic Velocities to Understand Subsalt Overpressure Drilling Risks in the Gulf of Mexico
Authors: den Boer Lennert , Sayers Colin Michael , Noeth Sheila , Hawthorn Andy , Hooyman Patrick James , Smith Martiris
Published: May 2011

As interest in drilling deepwater wells below salt in overpressured areas like the northern Gulf of Mexico continues to rise, the perceived value of reliable predrill predictions of subsalt pore pressure for mitigating drilling risk is also increasing. Higher-than-normal pore pressures are a significant hazard, especially when drilling below a laterally and vertically extensive salt canopy, where salt bodies are prone to form laterally isolated chambers or compartments with potentially distinct pressure regimes. This paper describes an approach used to estimate subsalt pore pressure in the deepwater Green Canyon area of the Gulf of Mexico. The approach uses a tomographically derived 3D estimate of seismic velocity. The quality of the seismic velocities allows an accurate model of the 3D salt distribution to be defined, the precise delineation of which is essential for accurate pore pressure estimation. While the method employed is able to account for overpressuring due to clay diagenesis, analysis of formation temperatures in the study area suggests that smectite-illite transformation is unlikely to occur within the depth range of available formation pressure data. The 3D pressure model derived demonstrates that subsalt pore pressure predictions can be obtained from seismic velocities given sufficient offset well data for calibrating a velocity-effective-stress transform.

Introduction

Drilling for hydrocarbons in a safe and economic manner requires that wellbore pressure be maintained between the formation pore pressure and the maximum pressure a formation can withstand without fracturing. Achieving this balance in overpressured areas is much more difficult, especially when factors such as clay diagenesis increase the risk. In these situations, a quantitative predrill prediction of pore pressure becomes essential. Predrill pore pressure estimates can be obtained from seismic velocities using a velocity-effective stress transform calibrated to offset well data. In this paper, tomographic seismic velocities from the Green Canyon area of the Gulf of Mexico are used to predict pore pressure below salt.

Tomographic Seismic Velocities

Seismic velocities often suffer from a variety of inaccuracies and limitations which render them unsuitable for pore pressure prediction. However, velocities obtained through iterative pre-stack depth migration (PSDM) have been shown to be of much higher quality (Sayers et al. 2002). Moreover, iterative refinement of tomographically derived velocities yields progressively better results, whose accuracy can be independently assessed by comparison with checkshots and sonic logs recorded in offset wells. Improved imaging implies that an accurate 3D model can be obtained, not only of the lateral and vertical salt distribution, but also of subsalt formation velocity.
A Combined Multiphase and Wetgas Meter with In-Situ Sampling of Fluid Properties
Authors: Wee Arnstein , Farestvedt Lars
Published: May 2011

Description

The MPM meter is a combined Multiphase and Wetgas meter, providing extremely accurate and reliable oil, gas and water measurements in production well streams. The meter is used topside and subsea, and is rated to 15,000 psi, 450°F, and 10,000 ft water depth. The patented technology utilizes a unique In-Situ Sampling method to measure and compensate for fluid property changes occurring in the well stream.

This paper presents the technical principles and test results from the qualification program and field installations covering multiphase, wetgas, and process control applications. It further discusses the In-Situ Sampling method and presents its performance in real life field applications.

Application

Accurate measurement of liquids and gas in multiphase and wetgas applications is extremely challenging. The meter must handle any combination of oil, gas and water, and must also be able to handle variations in the fluid properties to avoid significant OPEX and HSE risks related to topside and subsea fluid sampling and analyses. It is particularly important to eliminate the need of fluid sampling for H2S rich wells and deep water subsea developments.

Results, Observations, Conclusions

An extensive operator driven development and qualification program has been performed by ten oil companies. The In-Situ Sampling enabled the MPM meter to take measurements of the dominating fluid parameters in multiphase and wetgas applications. Methods for in line measurement of the PVT properties of the largest fraction in the pipe have been developed and qualified.

Significance of Subject Matter

In addition to the unparalleled accuracy, repeatability and reliability of the MPM meter in multiphase and wetgas applications, the meter - through its unique In-Situ Sampling method - is able to measure and compensate for fluid property changes, hence reducing and in many cases eliminating the need for fluid sampling. This is especially attractive for deepwater subsea applications, where fluid sampling is extremely challenging, has significant error potential, and is very expensive.
Standardized Test Cell Design Using Qualified Analytical Computer Modeling of Unplanned High Pressure Releases
Authors: Mann Michael , Wieczorek Dave , Skeels Brian
Published: May 2011

The oil and gas industry is continually demanding products that operate at increasing pressures and temperatures; frequently completion equipment, including wellhead systems and valves now require up to 20,000 psi (138 MPa) working pressures and factory acceptance test pressures up to 30,000 psi (207 MPa). As operators assume projects in greater water depths, deeper wells and more extreme temperatures, some completion product extensions will eventually require extreme working pressures of up to 30,000 psi (207 MPa). Currently, water and gas mediums are typically utilized to perform factory acceptance pressure tests to verify product integrity. Consequently, as the industry migrates to higher pressure and temperature applications, oil and gas service equipment poses increasing potential risk to personnel in the event of an unplanned pressure release. Therefore, utilizing qualified standardized shielding can be a key method in mitigating personnel and environmental impacts. Historically conservative mathematical models have been constructed to understand the behavior of a high pressure release and the adequate shielding to contain it. This paper details the development of standardized enclosures or " test cells?? using advanced computer simulation software to model energy imparted from the flow characteristics of a gas blast, in addition to the energy from a projectile during the event of an unplanned pressure release. The resulting computer model simulation comprised of both Computational Fluid Dynamic (CFD) and mechanical Finite Element Analysis (FEA) simulations is then validated through testing of a pressure release up to 30,000 psi (207MPa). Once the computer model is validated, it can be utilized to determine minimum shielding requirements for varying high pressure testing applications.

Introduction

Pressure testing in the oil and gas services industry is often used to verify the product integrity. In addition to product design, an engineer must also design a test and corresponding equipment to ensure the safety of the personnel performing the respective scope of work. As the potential failure modes become increasingly catastrophic with higher pressures, the utilization of models that can accurately account for the cumulative impact of energy imparted from the combined effects of a projectile and corresponding gas blast is critical. This type of analysis is complex, as often times the behavior of an unplanned pressure release is impacted by many key variables:Initial distance from the shieldTest volume and fluid characteristicsTest pressureProjectile material and sizeProjectile interface characteristics with the test body

Test parameters and conditions vary considerably in the oil and gas service industry, and modeling each individual test case for shielding evaluation is not feasible. Therefore, defining standardized enclosures which can be utilized across the industry can be a streamlined approach for improving personnel safety in the field.
High Active, Dispersion Based Paraffin Inhibitors for Subsea Applications
Authors: Huijgen Martijn C. , Grondman Herman , Oschmann Hans-Joerg
Published: May 2011

Production of waxy crude oils can be challenging due to increased viscosity, restart issues and wax deposition. Due to a decrease in solubility of high molecular weight paraffins in waxy crude oils with decreasing temperature, paraffins precipitate and deposit on pipeline walls or form a 3-dimensional network in which liquid oil becomes trapped. Even for crude oils with low to moderate wax content, where viscosity and restart issues may not be a critical factor, deposition could be a huge problem when (subsea) flowlines are being affected and flow restricted.

Among other options available, chemical treatment with pour point depressants and / or paraffin inhibitors is used to impede wax related problems. Specific high molecular weight polymers, changing the wax crystallization process are commonly used as the active components in these pour point depressants and paraffin inhibitors. The products are formulated in solvents to allow for easy pumping and injection.

To achieve interaction with crystallizing paraffins, functional groups of the polymers are similar to wax and as such the polymers themselves are difficult to dissolve. Particularly for application in deepwater, subsea or cold climates, low active formulations are used which require high dose rates.

To overcome these typical problems, dispersion based products have been used for a number of years. High active dispersion base products have been successfully applied in land based operations as well as topsides offshore. New developments in formulating dispersion based PPDs and Paraffin Inhibitors has resulted in products suitable for subsea injection. One of these new environmentally friendly developments was proposed for inhibiting wax deposition in a subsea tieback in the Norwegian sector of the North Sea. Following lab evaluations that confirmed the performance of the product, the product has been successfully applied through a subsea injection line. This paper will discuss development, practical application and benefits of such products.
Nuclear Industry Concepts for Safety and Performance Management and Application to Offshore Operations
Authors: Nelson Bill
Published: May 2011

The commercial nuclear power industry has developed and applied improved methods for safety and performance management since the accident at Three Mile Island (TMI) in 1979. These include methods for risk management, identification and application of lessons learned, risk informed regulation, and safety culture improvement. Methods have also been developed to identify strategies and procedures to manage severe accidents - e.g. events outside the design basis that formed the envelope for the initial operating license. The combined implementation of all these technical, organizational, and regulatory changes has led to a significant industry-wide improvement in the performance of nuclear power plants in the US since TMI. This paper summarizes these developments in the nuclear industry, describes a recent application to risk informed safety culture assessment for a Canadian nuclear power station, and explores the potential to apply these methods for design, operation, and regulation of offshore facilities as part of the industry response to the Deepwater Horizon accident.

Nuclear industry practices prior to Three Mile Island

From the beginnings of the commercial nuclear power industry in the United States in the 1960's the primary unifying concept for demonstrating safety was the Design Basis Accident (DBA). A design basis accident is a postulated event that the plant must withstand. The Safety Analysis Report (SAR) for each facility was required to demonstrate that the plant could withstand the occurrence of specific prescribed DBAs. Examples include loss of coolant accidents (LOCAs), reactivity accidents, steam generator tube ruptures, loss of offsite power, etc. In addition to forming the basis for demonstrating that the plant could be operated safely within a prescribed " safe operating envelope,?? DBAs also established (perhaps inadvertently) the basic paradigm for the development of emergency operating procedures. Similarly, the design of instrumentation was intended to provide information up to but not beyond the conditions expected during a Design Basis Accident. Hidden within the emergency procedures were the assumptions that plant operators would be able to accurately diagnose the event in progress, and their major role would be to monitor the performance of automatic systems and only intervene when automatic systems failed to actuate or to restore normal conditions once the automatic systems had carried out their assigned functions. Finally, there was likely an unconscious assumption that events more serious than the design basis accident would not (or perhaps could not) occur, and that if a plant could withstand the DBAs then safety was assured for other conceivable accident sequences. Unfortunately, as we shall see later, these numerous, often unspoken assumptions were fundamentally flawed.
Overview of the SAFEBUCK JIP
Authors: Bruton David A.S. , Carr Malcolm
Published: May 2011

This paper summarizes key areas of research and development undertaken by the SAFEBUCK Joint Industry Project (JIP), including the development of engineering models and the testing of pipe-soil interaction, fatigue and local buckling.

The SAFEBUCK Joint Industry Project set out to address one of the key design challenges for pipelines - buckling due to the compressive forces created by internal pressure and temperature - by supporting and guiding a design approach that deliberately encourages pipelines to buckle, but in a controlled way. By controlled initiation of lateral buckles at regular intervals, the loads are shared and reduced at each buckle site. Early application of this idea was hounded by problems due to a lack of know-how, which led to a number of failures, including three full-bore ruptures and one abandonment, mostly due to the issue not being addressed correctly in design. A related challenge addressed by the JIP, is pipeline walking, which has been observed on a number of pipelines, leading to one failure and a number subsea interventions to prevent future failure.

With the JIP now entering its third and final phase, the design guideline and research findings have been applied on a number of projects. This is therefore a good opportunity to present the SAFEBUCK design methodologies and research to a wider audience, and outline work underway now, in the final phase. A series of papers follow in the same session at OTC 2011, to provide more detail on the SAFEBUCK Design Guidance, research findings and the practical application of this technology to the lateral buckling and walking of pipelines.
How MPD with Advanced Flow Detection System was successfully applied on an eHPHT Well in the Norwegian North Sea
Authors: Naesheim Sigve Krohn , Lefdal Frode , Oftedal Tor Oyvind , Sveinall Henrik
Published: May 2011

This paper will describe an actual field example of how a Managed Pressure Drilling (MPD) system was successfully used onboard the Heavy Duty Jack Up (HDJU) " Rowan Gorilla VI?? to successfully drill the Mandarin East eHPHT exploration well on the Norwegian Continental Shelf. The well is the most extreme well with regards to temperature and pressure ever drilled in Norway. The primary premise for the use of MPD in this case was that the well was always to be in statically balanced/ over balanced condition.

The well was drilled to a TD of 5933m MD RKB in formation of Triassic age. The wells location was carefully selected to avoid seabed conditions with high risk of punch through for the legs of the jack up rig and also to avoid potential accumulations of shallow gas pockets in the area. Although there were some offset wells in the area, the " Mandarin East?? well was going deeper than any of the offsets and, hence, had to be treated as a rank wildcat with regards to both geology and pressure.

Pressure evaluation and kick detection was viewed as very critical to the well success as the estimated surface pressure was very close to 15,000 psi. The most important factor in the well design was to get the 9 7/8?? production casing shoe as close to the potential reservoir as possible to obtain a fracture gradient that allowed for drilling the 8 ½?? hole section to TD with very narrow margins between the pore pressure and the fracture pressure. As experienced on most conventional HPHT wells, also the " Mandarin East?? well was expected to face significant well bore breathing challenges.

The rig RGVI belonging to Rowan Drilling is a Super Gorilla design jack up rig and it is very well equipped with regards to suitability for HPHT drilling. Prior to spudding the " Mandarin East?? well, the RGVI had recently drilled two eHPHT/HPHT wells in UK and the crews were already familiar with standard HPHT procedures.

Based on the drive to enable drilling an 8 ½?? hole to TD to facilitate a DST test in a discovery case and to, potentially, save time and cost in handling kicks and well bore breathing issues, it was decided to utilise Managed Pressure Drilling (MPD) equipment that used a closed circulation system, a Coriolis flow meter and flow detection algorithms to provide an early kick detection system.

This paper highlights the rig preparations made to accommodate the use of MPD equipment and the importance of structured and organised management in the rigorous process of preparing " tailor made?? procedures and training/preparing the rig crews for operating outside the " normal?? HPHT procedures. Furthermore, the paper highlights the experiences and many lessons learned after successfully drilling the eHPHT well " Mandarin East?? to TD. It is estimated that the MPD system saved 10 days of rig time/ US $ 7.5 million in addition to the improved HSE aspects of using this system.
Advances and Impact of Software-Based Deepwater Blow Out Preventer Testing
Authors: Franklin C. Mark , Sargent Timothy L. , Brown Charles Ray , Owen Gary , Griffith Steve , Osmond Jeremy Warwick , Gronas Tore , Cully Richard
Published: May 2011

To advance the technology of BOP leak detection through a software development initiative, operators, service provides, and drilling contractors established an industry consortium in early 2009. The initial development focused on the testing of BOPs in deepwater. Upon completion of the pilot program on five deepwater rigs, the results exceeded original expectations. The test results proved the software was effective, efficient, and rig friendly. Once a test plan was constructed, with the click of the " Start?? button, the software was completely automated, up to the time of printing the report.

Through an iterative and collaborative process, a unique solution for the Low Pressure (LP) and High Pressure (HP) BOP testing has been developed. For example, due to the constraints and subjective nature of the current Circular Chart Recorder (CCR) methodology for validating a test, a small leak may not be identified for up to 30 minutes into the HP test. With this new methodology, objective identification of a slow leak typically occurs during the LP portion of the test in less than three minutes; and a good test (no leak) typically validates in the regulatory agency's minimum holding time requirements. Additionally, the software provides greater assurances, transparency, and reliability as compared to the CCR. The antiquated CCR is easily manipulated in multiple ways, which is eliminated with this solution.

This software provides the industry with a tool for objective, efficient test validation. The software generates simple, clear, concise reports and contains more information as compared to what is currently available. It archives tests in a secure format, and the software allows the users to retrieve and review the tests for any required scrutiny. It also prints the reports to a secured PDF format and archives them.

This paper discusses the current state of the development along with the associated benefits. A vision of the application development pipeline for further pressure analysis opportunities is also introduced.

Introduction

The oil and gas industry has advanced very little with respect to pressure testing critical equipment on drilling rigs. As the industry moves into operating in deeper water and uses non-water-based fluids, the challenges associated with obtaining effective pressure tests continue to grow.

Historically, digital pressure measurement solutions had not been considered due to its accuracy. Prevailing interpretations of regulatory requirements to " hold pressure?? were to demonstrate a flat-line on a pressure chart for a specified period of time. With the relatively low resolution of a CCR device, a flat-line was essentially produced when the resolution of the device was exceeded (typically 4-6 PSI). Analog chart recorders had the additional " benefit?? of allowing excessive damping and manipulation without recording such settings or actions.
Maximize Offshore Reservoirs Productivity with the Latest Design Techniques and Advanced Centrifugal Compression Technologies
Authors: Costantini Stefano , Grifoni Luciano , Rubino Dante Tommaso , Corneloup Christophe , Baldini Bernardo
Published: May 2011

Compressors installed in plants worldwide can be modified to meet new operating conditions and other specific customer needs. This basic concept is even more relevant in offshore application. Timely upgrading of the centrifugal compressors to suit the late life requirements of the reservoir means, in fact, increasing hydrocarbon recovery versus reservoir depletion.

GE Oil & Gas has accumulated extensive experience in upgrading Centrifugal Compressors. Customers can benefit from implementing GE Oil & Gas new technologies and modeling methods that allow the extension of the operational envelope of the compressors beyond that previously possible in a predictable manner.

This paper shows the solution adopted by applying GE Oil & Gas design, testing and offshore installation methodologies in the context of brown field constraints to extend gas field production achieving up to 5 additional years through a new re-bundle inside existing casing, obtaining +50% extra polytrophic head versus existing machine and with a new, tailor made, centrifugal compressor, same footprint, obtaining +130% polytrophic head versus original one.

INTRODUCTION

Centrifugal compression facilities for Natural Gas Export and Enhanced Oil Recovery are affected by substantial changes in the operating conditions, which are the consequence of the reservoir depletion. Compression unit retrofit can be applied to offset those changes by increasing the compressor unit pressure ratio and/or flow rate.

At the end of the 90's GE Oil & Gas started to partner with End Users to retrofit the existing equipment by, mainly, changing centrifugal compressor internals, whose design was performed to center the machine envelope to the new operating conditions (as set by the analysis of the constrains, the goals and the thermodynamic performances of the available technology at that time).

A decade of experience accumulated in retrofit jobs in both offshore and onshore fields proved that cost effective projects are deliverable by lining up the machine internal stator and rotor components (re-bundle) to new operating conditions, this way avoiding off-design operation and allowing the retrofitted compressor to run outside its original envelope with increased operational efficiency.

In the early 2000 GE Oil & Gas started research activities, dedicated to retrofit applications, to develop the aerodynamic performances of the centrifugal compressor impeller stages to further enhance the existing assets value by combining the above approach (retrofit the machine to center it to new operating conditions) with the extra performances of advanced aerodynamic design developed to meet the constrains of brown field jobs.
Midstream & Subsea Pipeline Condition Monitoring
Authors: El Hares Layla , Strong Andrew Peter , Le Stanc Patrick
Published: May 2011

In this paper we present a fully integrated pipeline and flowline integrity monitoring system. The system uses optical-fiber distributed sensors to provide simultaneous distributed measurements of temperature, strain, and vibration for the detection, monitoring, and location of events includingthird-party interference (TPI), including multiple simultaneous disturbancesriser strain, pipeline buckling and upheaval, geohazards, landslides, and ice scoursVortex-induced Vibration (VIV)flow assurance and distributed temperature monitoring of heated pipelinesgas and oil leakspermafrost protection.

The technology also provides a unique means for tracking the progress of cleaning and instrumented pigs using existing optical telecoms and datacoms cables buried close to pipelines.

The solution provides a unique and proactive approach to pipeline integrity management. It performs analysis of a combination of measurements to provide the pipeline operator with an event-recognition and location capability, in effect providing a hazard warning system and offering the operator the potential to take early action to prevent loss.

Through the use of remote, optically powered amplification, an unprecedented range of 100 km is possible without the need for any electronics or therefore remote power in the field. A system can thus monitor 200 km of pipeline when configured to monitor 100 km upstream and downstream from a single location.

As well as detecting conditions and events leading to leaks, this fully integrated system provides a means of detecting and locating small leaks in gas pipelines below the threshold of present online leak-detection systems based on monitoring flow parameters. Other significant benefits includepotential reductions in the construction costs of new pipelinesenhancement of the operator's existing integrity management programPotential reductions in surveillance costs and HSE risks.

In addition to onshore pipeline systems, this combination of functionality and range is available for practicable monitoring in a wide range of other applications, such asthe monitoring of long subsea flowline for flow assurance, leak detection and movements such as ice scourflexible riser integrity monitoringstrain and shape monitoring of offshore riser and umbilical systemsFacilities perimeter security.

An important element of this system is a bespoke direct-bury optical sensor cable, designed to allow distributed strain measurement and hence enable monitoring of ground movement whilst withstanding the rigors of pipeline environment. The system can also be configured for detection of third-party interference and leaks with the majority of existing buried onshore cables.
Steel Tube Umbilical Design Life Verification by Full-Scale Fatigue Test
Authors: Brown Ewan
Published: May 2011

Steel Tube Umbilicals (STUs) are integral to many offshore production systems and must be designed to endure demanding fatigue environments over the course of their service life. It is therefore fundamental that the design methods employed to calculate the fatigue life of STUs are suitably validated against real test data.

This paper compares the predicted STU fatigue life derived using UFLEX2D analysis with that observed by flex cycling a manufactured sample to failure. Characteristics such as tube helical geometry, internal pressure, tension, bending, and friction stick-slip behaviour are considered. Calculated strains are presented alongside strain gauge measurements taken from the sample, and fatigue lives derived using DNV-RP-C203 are compared against the actual numbers of cycles for tube through wall-thickness cracks to develop.

INTRODUCTION

Oceaneering Umbilical Solutions (OUS) continues to invest in improving engineering technology and has key focus on developing accurate analysis techniques for designing reliability into its STU products. The past 2 years have seen a number of new initiatives including participation in the Umbilical Phase II JIP with Marintek to support development of the non-linear FE analysis code UFLEX2D and providing sample umbilicals to the project for test and validation work.

More recently work has been carried using UFLEX2D to compare the theoretically predicted fatigue life of an STU against a full-scale flexure test to failure. This paper provides a description of the analysis approach and results of the test.
Safety Case For Gulf Of Mexico - What Would It Mean? A Global Case Study Of The Application Of A Safety Case Regime
Authors: Alme Inge , Wingate Kyle , Dunn Cameron
Published: May 2011

In response to the disaster in the Gulf of Mexico, the U.S. government under the advice of various independent reports and analyses is considering significant revision of the rules and regulations with respect to offshore operations. Part of the proposed changes includes the move to use Safety Case based regulations to govern operations in the Gulf of Mexico Offshore industry.

Scandpower and Lloyd's Register have been completing safety case preparation, review and implementation for offshore assets in the North Sea, UK sector, Canada, Australia, China and Brazil for many years. Through our database of safety cases and their application to various asset types, this paper shows how the safety case regime could be applied to typical assets in the Gulf of Mexico.

The various tasks and stages of the Safety Case will be discussed in conjunction with the overall objective of the application of the Safety Case. Examples will be discussed from various regulatory regions to highlight variances in risk analyses, and how these affect the preparation and outcome of the regime. Since the main purpose of the safety cases is to show compliance with the relevant rules and regulations related to safety, the safety cases developed for different regulation regimes differ significantly with regards to detail level, methodologies applied and amount of documentation. However, the main structure of a safety case is more or less the same in all regimes and is based on widely accepted international standards.

Introduction

Several investigations of the Macondo oil spill in the Gulf of Mexico have been ongoing throughout 2010, and a common theme for many of the findings is related to the approach to how safety should be controlled and regulated. As an example, the following is stated as one of the recommendations in the National Commission's report to the president (ref./1/): " The Department of the Interior should develop a proactive, risk-based performance approach specific to individual facilities, operations and environments, similar to the " safety case?? approach in the North Sea.??

This paper serves industry as a brief historical review in the use of the Safety Case and expectations for its application in the Gulf of Mexico DeepWater and Nearshore Regions.

It is based on Scandpower's and Lloyd's Register's experience from our worldwide operations, but also from reviewing the ongoing changes in the regulations for operations in the Gulf of Mexico.