bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Safety and Environmental Management System Rule
Authors: Sutton Ian S. 
Published: May 2011

Abstract
In October 2011 the United States Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) introduced its Safety and Environmental Management System (SEMS) rule. It became effective November 15th 2010; companies operating on the Outer Continental Shelf (OCS) under the jurisdiction of BOEMRE must be in compliance with its requirements by November 15th 2011. The rule is based on the Safety and Environmental Program (SEMP), which is part of the API (American Petroleum Institute) Recommended Practice (RP) 75 (API 2004). RP 75 was first published in 1994; the most recent edition is from the year 2004.
The SEMS rule is lengthy and its requirements are demanding. Not only has BOEMRE incorporated SEMP into law, the agency has added many additional requirements, some of which are quite substantial. (Hence, the statement " SEMS is SEMP?? is somewhat misleading — there is a lot more in SEMS than there is in SEMP.) The timing of the rule is particularly demanding — particularly for those companies and facilities that do not currently have an up to date SEMP in place.
The manner in which the new rule will be enforced is also important. It is likely that BOEMRE will be considerably more assertive in enforcing rules and standards than was its predecessor, the Minerals Management Service (MMS). For example, although the moratorium over new deepwater drilling that was put in place following the Deepwater Horizon event has been lifted, the agency has continued to make it very difficult for companies to actually obtain permits.
This paper provides a brief historical background as to how SEMS came to be. It goes on to discuss the requirements of the rule, and then provides some guidance as to how its requirements can be addressed in an expedient and defensible manner, particularly by those companies who do not already have a complete SEMP in place.
Finally, it should be noted that, when the original Abstract for this paper was being written, the SEMS rule had not been promulgated. Some of the assumptions made at that time — such as a requirement for Production Safety Cases — did not materialize. It is likely that the SEMS rule, along with some of its associated standards, will change some more over the course of 2011 and 2012. Therefore, it is very important that anyone who is implementing or running a SEMS program check to see if the rule has been updated, or if any material changes have been made to the pertinent API standards.

Historical Background
The development of Formal Safety Management systems for offshore facilities can be said to have started with the Piper Alpha catastrophe that occurred in 1988. Of course, companies working offshore had had safety programs before that time, but Piper Alpha is often viewed as being the starting point for the development of formal Safety Management Systems for offshore operations — world wide. This development is illustrated in Figure 1.
Understanding the Effects of Deep-Sea Conditions on Seafloor Massive Sulfide Deposits Crushing Process
Authors: Waquet Benoit , Faulds Donald , benbia ali 
Published: May 2011

ABSTRACT
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract

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.