bluuebunny/crossref_metadata_2025_split huggingface dataset:
API RP2T and RP2FPS: Moving Forward
Authors: Leverette Steven J. , Wolfram Bob 
Published: October 2008

Abstract
API is developing updates for two key floating/tethered system documents for issuance in 2008. Impactful changes in RP 2T based on learnings from the 2004-2005 hurricane season, over 10 years of experience and technology development and metocean changes have been incorporated. Additional criteria regarding tendon loss/damage and an integrity check for conditions significantly above the 100 year design basis will be discussed.
API RP 2FPS is being developed using ISO 19904 as a basis (19904 was built upon the current version of RP 2FPS and updated) and " wrapped?? with US Gulf of Mexico specific additions.
This paper will present the key changes/additions in these documents and provide a discussion as to the impact.

Introduction
From the first floating production systems in the 1970's and early 1980's, semisubmersibles, FPSOs, TLPs, and more recently spars have featured prominently in the industry's vision of how to produce oil in deeper water depths. The first floating production system, a converted semisubmersible, was developed in the North Sea for the Hamilton Brothers' Argyle field (1974). The first FPSO was installed on the Shell Castellon field offshore Spain in 1977. The first production TLP was installed in the Conoco Hutton field (1981) in the North Sea. Since then, there have been many floating production systems successfully installed in locations all around the world.
The first API recommended practice to address these structures was RP2T, the Recommended Practice for the Planning, Design, and Construction of Tension Leg Platforms, first issued in 1987. Until recently, RP2T was the only issued API document to address floating production systems. Although RP2T was limited to TLP's, it served as a technical basis for other types of structures, along with various classification society documents and European codes. In 2001 the first edition of RP 2FPS was issued.
As the industry has developed more experience with these structures, the body of information available for guidance to designers, builders, and operators has expanded, while the methods and practices have evolved and improved. In response to this evolution, API typically issues updates to incorporate the new information. The impetus for issuing an updated RP2T and a new RP 2FPS at this time includes a number of factors. The technology for both FPS's and TLP's has evolved to include varied concepts and configurations. The engineering tools and practices have greatly improved. And finally, the understanding of the environment, especially in the Gulf of Mexico, has changed significantly following the 2004-2005 hurricane seasons.
One other evolution in the API offshore structure recommended practices has been brought about by the progress made in the standards developed by the International Standards Organization (ISO). When the ISO first started to develop offshore structure standards, there was a move within API to eventually replace the API RP's in favor of the international standards.
First use of Swell Technology in Campos Basin Proves Water Conformance Solution - Case History in Campos Basin-Brazil
Authors: Ueta Eduardo Midufo , Neto Jose Nolau , Nunes Max Amado , Barrios Oscar D. , Tocchetto Andre Luiz Rodrigues , Barretto Neto Edison Baptista 
Published: October 2008

Abstract
The Pampo Field is in southern Campos Basin, Rio de Janeiro, Brazil and contains sandstone and shale reservoirs with good quality oil (14 to 32 API). In Dec. 2004, a major operator in the region drilled a horizontal well, which was completed with an openhole gravel pack. During production, water break through was noted from the upper producing part of the reservoir in the horizontal section, and this phenomenon steadily increased. Due to the higher hydrostatic pressure from the water-producing area, oil production from the lower section of the reservoir was inhibited. A work over was performed to isolate the water-producing zone by isolating the interior of the gravel screens.
This paper will discuss a new technology for the Campos Basin area that was capable of resolving the water production problem. A concentric string was developed to run inside the gravel pack screens and included sliding sleeve circulating devices and two swellable packers that were connected at the end of the string and were spaced out to isolate the water producing shale. The objective of this configuration was to decrease flow from the upper producing portion of the sandstone to isolate the water production area and allow higher production from the lower producing portion of the sandstone (3595 to 3935 m).
Swellable packer technology was successful in providing the required results. In this technology, a rubber configuration that expands to create a permanent seal when exposed to liquid hydrocarbons such as crude oil, diesel, oil-based mud, etc. is placed around the packer, and thus, when it expands, it can provide a long-term water shut-off tool. This case history will show that the swellable packers:Performed with predicted results from the simulated designHelped reduce water productionGained operator approval for other operations.
This paper describes the well scenario in which swellable packer technology was used to perform zonal isolation in an offshore horizontal well in Campos Basin, Rio de Janeiro, Brazil to effectively control water influx and manage oil production.

Introduction
The Pampo concession is situated in the southern part of the Campos Basin, approximately 80 km from the Rio de Janeiro state coast. Water depth is approximately 108 m. Figure 1 is a map of the area and shows the Pampo Field. Several lithologies including carbonates, sandstone and conglomerates prevail in the target formations. The producing formation is from the upper and lower sandstone located above and below the shale section. The oil produced from these formations is of good quality with gravity ranging from 14 to 32 API.
New Design in Surface-Controlled Subsurface Safety Valves Resolves Valve Problems in Subsea Completions in the Gulf of Mexico
Authors: LeBoeuf Gerald Joseph , Adams Shane Michael , Pittman Adam , Dodd Paul 
Published: October 2008

Abstract
Shell has been developing wells in the Gulf of Mexico (GOM) in environments that have required 10,000 psi working pressure surface-controlled subsurface safety valves (SCSSVs). The well environments have been sweet service with up to 11,750 psi bottomhole pressures and depths of up to 18,000 ft and SCSSV setting depths of approximately 7,600 ft. Valve failures have not only compromised well integrity but also resulted in production down time, as a SCSSV fails to a closed position. Additional cost is also incurred in order to recomplete the wells. Although failures in current nitrogen-charged SCSSVs and the valve operating systems are not as common as they once were, the incurred costs from these failures prompted a search for an improved safety valve. Requirements were determined for the sought-after safety valves, and the following discussion provides the list of critical needs.
The primary requirement was that the sought-after safety valve be capable of maintaining integrity in the above conditions and be compatible with 4-1/2-in. tubing and 9-5/8-in. casing. To comply with the well design, the SCSSV would require capabilities that would support the following parameters:Dual line set-up for operation of SCSSV and balance of control-line fluids across operating pistonNon-tubing pressure sensitiveLower operating pressuresOperating system isolated from wellbore pressureDebris protectionSetting at any depthFewer moveable parts and seals than other SCSSVs.
A unique magnetic coupler SCSSV that met the required capabilities is the focus of this paper. The new SCSSV offered several advantages that were important to Shell.
The design of the valve, a comparison with traditional valves in similar well conditions, and the first installation for Shell will be presented. The new valve is successful, and as a result, four additional installations using the magnetic coupler valve have been scheduled.
Diving Bell Escape Systems: Some Observations and Test Results
Authors: Nuytten Phil 
Published: October 2008

ABSTRACT
The operation of deep diving bell systems (SDC's) onboard today's offshore drilling vessels has become a routine exploration tool. Virtually all diving support contracts specify system depth capability to at least 600 feet and, in many cases, to one thousand feet.
With well over one hundred such systems currently operating in the waters of the world, the inevitability of emergency situations that may require diver abandonment of the SDC is an alarming spectre. Entanglement of the SDC, toxic contamination of the SDC atmosphere and entrapment by structural failure are just' a few of the potential hazards that could cause an emergency abandonment situation or a prolonged bottom stay awaiting rescue.
This paper examines some D£ the procedures programmed for use during a bottom emergency, the viability of commonly accepted but little used safeguards and briefly discusses the specific problems of recovering a disabled SDC or having the occupants leave an irretrievable SDC and ascend to the surface.

DIVING BELL ESCAPE SYSTEMS: SOME OBSERVATIONS AND TEST RESULTS
Under normal operations, the submersible diving chamber (SDC) or diving bell is lowered and raised from the work platform by means of a strength wire. Few, if any, of the SDC's operating around the world have any means to effect a controlled surfacing should the strength line become severed or otherwise detached or the SDC become entangled on the bottom. There are. a number of possible situations that could prevent the SDC from being raised to the surface station in the usual manner. A detailed examination of these potential situations may cause some reflection on the adequacy of existing emergency measures and the possible consideration of modifications and/or the formulation of additional measures.
The recent, well publicized tragedy involving the submersible "Sea Link" is a graphic illustration of the type of situation which may be encountered in the petroleum exploration support role. The SDC's usually operate under conditions where speedy outside assistance, in the event of an emergency, is logistically impossible and reliance must be placed on whatever self-contained measures are available or can be programmed.
There are at least five major factors to consider in programming emergency procedures:Nature of the problem (e.g. is the SDC entrapped?Depth of water (e.g. possible to use standby diver?Umbilical condition (e.g. severed or intact?Load line condition (e.g. severed or intact?SDC pressure condition (e.g. pressurized or unpressurized?
If one fixed case is assumed for question "A" - the SDC is entrapped - the critical examination of the possible combinations of other factors will require a detailed analysis of at least sixteen possible situations and the calculation of the most effective emergency procedures to use in each case.
Hydrates Blockage Experience in a Deepwater Subsea Dry Gas Pipeline: Lessons Learned
Authors: Kane Moussa , Singh Aditya Pratap , Hanssen Ronny 
Published: October 2008

Abstract
The Matterhorn field, operated by TOTAL, is located in the Gulf of Mexico, on block 243 of the Mississippi Canyon. It produces oil and gas from seven wells in a water depth of approximately 2800 ft.
This paper reviews a hydrate blockage incident which occurred on the Gas Export Pipeline (GEP) of the Matterhorn platform. A comprehensive flow assurance study (fluids characterization, steady state and transient flow simulations) was conducted in order to understand the causes of the incident and to develop prevention, mitigation and remediation strategies. The study described herein gives a methodology to be used in the design and operation of gas pipelines, principally in the deep water subsea environment, from a hydrate management perspective.
The GEP was operated in the hydrate-stable and two-phase region, but still within industry standards in terms of dryness (dewpoint). The study shows that a temporary deviation from the normal operating conditions lead to a gradual water build-up, resulting in hydrates formation and eventually causing a total obstruction. The transient simulations performed with OLGA® were able to predict the condensate and water accumulation rate and holdups along the GEP.
The incident described and the subsequent flow assurance study highlight the potential risk of hydrates formation in " dry?? gas pipelines in deep water subsea environment. In subsea gas export lines, the current dryness (dewpoint) contractual requirements agreed upon by the operators are believed to provide safe operating conditions with regard to hydrates. The present work demonstrates that hydrates formation risks remain even when operating within the industry requirements. The remediation strategy adopted after the hydrate blockage, and the prevention measures applied since, provide useful guidelines for the management of hydrates in gas pipelines.

Introduction
With oil and gas developments moving to ever deeper subsea environments, hydrates-related issues become a growing concern for the industry. Hydrates blockages, beyond the safety risk they represent, result in time-consuming and costly mitigation and remediation operations. Most hydrates experiences found in the literature, and the corresponding prevention and remediation strategies, concern multiphase pipelines. This paper relates a hydrates blockage incident which occurred in January 2007 on a deepwater dry gas pipeline. A detailed review of the events and subsequent remediation actions is given, along with an analysis, including a PVT study and transient multiphase simulations.
The lessons learned from this experience are presented here and are currently being used as a basis for improving operation guidelines and hydrates prevention strategies for dry gas deepwater pipelines.
Subsea Equipment Installation Challenges for Malaysia's First Deepwater Development
Authors: Murray Gordon , Stensgaard Thomas , Lowther David , Ledingham Adrian , Robertson Ian 
Published: October 2008

Abstract
The Kikeh Development is the first deepwater project in Malaysia located Offshore Eastern Malaysia in the South China Sea with a water depth of 1320 m. Kikeh is produced via a Spar and a subsea water injection and production system back to a Floating Production Storage and Offloading (FPSO) unit (see Figure 1). Kikeh is planned to be developed using 34 wells and initial production commenced in August 2007.
The main subsea installation portion of the Kikeh development was executed through an Engineering, Procurement, Construction, Installation, and Commissioning Support contract with Technip Marine (Malaysia) Sdn Bhd. The installation scope of work included the following:5 manifold support piles*5 subsea manifolds*5 flexible risers and flowlines with a total length of over 31 km of flexible pipe7 riser holdback anchor piles4 electro-hydraulic control (EHC) umbilicals (2 dynamic/static and 2 infield static)*5 rigid spools c/w vertical connection module (VCM) clamp connectors (out of 14 in total)*5 subsea distribution units*6 hydraulic flying leads (out of 27 in total)*6 electrical flying leads (out of 48 in total)*Pre-commissioning of the subsea systems
* Free issued from subsea equipment EPCC contractor
The paper will discuss the process of offshore installation vessel selection including the effects on the decision process of utilizing local equipment versus mobilizing deepwater construction equipment from other deepwater basins around the world.
In addition, with deepwater Sabah being a greenfield deepwater basin, a number of challenges arose in relation to availability of equipment within the region and logistics to support the deepwater construction operations. Highlights from Phase I, Phase II, and Phase III installation programs are also presented.
The Next Major Challenge for Deep Water: Developing Marginal Fields
Authors: Millheim Keith K. 
Published: October 2008

Abstract
Worldwide, there are hundreds of deep water oil fields that have been discovered, and many hundreds yet to be discovered that are not commercial using existing conventional deep water approaches. A new paradigm based on production materiality is an alternate approach for deep water marginal oil field exploration and development. This new paradigm shows that first oil could be consistently achieved in one to two years from discovery to first oil with attractive economics if there are new ways to significantly reduce drilling costs, capital investment, and operational costs. This paper presents a paradigm of how these results might be possible in the foreseeable future with the innovation of what might be called the micro chip for deep water—the self standing riser.

INTRODUCTION
History of the oil industry shows the early discoveries of oil and gas started with the shallow, easiest to find hydrocarbons, onshore. With innovations in seismic and drilling equipment and technology deeper discoveries were made. Later exploration was extended offshore to the shallow shelf areas. The North Sea and Gulf of Mexico (GOM) and offshore Brazil led the development of offshore technology which focused on drilling with jack-ups, drill ships, and semi submersibles with most of the production facilities based on compliant platform structures. However, as smaller fields were discovered and field extensions extended beyond the reach of the drilling/production platforms the subsea well became a viable option. Subsea wells near the platform were tied back via pipeline to the platform. However, in some cases, a floating production unit (FPU) was used to process the subsea well(s) production and tie back to the main production line. Other cases where the tie-back to the main pipeline was not feasible a floating production storage off-take vessel (FPSO) was used not only to process the reservoir fluids but also to store the oil for later pick up by an oil tanker. For most of the world (except for the Gulf of Mexico), especially the North Sea, Brazil and Australasia, the subsea well and FPU/FPSO became the normal development path for the smaller offshore fields. The FPU/FPSO offered more versatility, quicker construction, and in most cases better economics.
The Gulf of Mexico was a unique case where there has always been enough offshore pipeline infra-structure where all the oil and gas production went into the main pipelines. Because of the pipeline network and some other perceived safety and environmental issues the use of FPSOs was non-existent. Only a few FPUs were commissioned in the GOM.
In the middle of the '80s the exploration community, with the help of advanced seismic technology, showed the likelihood of finding large oil fields in deeper water with Brazil leading the way. Deeper water discoveries in the GOM and West Africa followed. Except for the Middle East few places held the potential for the discoveries of big fields like deep water.
SS: Panel- Session on Risk Management in the Offshore Energy Industry, International Risk Management
Authors: Murphy Daniel V. 
Published: October 2008

Abstract
Executing any design or construction project involves risk, and complex projects have a potential for even greater risk. The function of project management is to establish processes which control the performance of work by the project participants. Project managers plan project execution around the expectation that events will occur within a ‘normal’ range, both temporal and financial. The intent of managing risk is to establish a program to prepare for both negative and positive risks which manifest outside of this normal range. While certain risks, such as property damage, are frequently insured, many risks are not. In this paper, the term Project Risk will refer to these abnormal risks and Project Risk Management will refer to the efforts required to exert control over the impact of Project Risks. In 1992, The Project Management Institute (PMI) defined Project Risk and Project Risk Management (Reference 1) as follows:Project Risk is the cumulative effect of the chances of uncertain occurrences adversely affecting project objectives.Project Risk Management is the art and science of identifying, assessing, and responding to project risk throughout the life of a project and in the best interests of its objectives.
In 2001, another definition of Project Risk Management was stated as follows (Reference 2):
Risk management is the act or practice of dealing with risk. It includes planning for risk, assessing (identifying and analyzing) risk issues, developing risk handling options, and monitoring risks to determine how risk has changed.
By 2004, PMI had modified its definition in the Guide to the Project Management Body of Knowledge (Reference 3) as follows:Project Risk is an uncertain event or condition that, if it occurs, has a positive or negative effect on at least one project objective…the cumulative effect of the chances of uncertain occurrences adversely affecting project objectives.Project Risk Management includes the processes concerned with conducting risk management planning, identification, analysis, responses, and monitoring and control on a project; most of these processes are updated throughout the project.
In this same Guide, PMI goes on to establish the purpose of Project Risk Management as follows:Specifically identify factors that are likely to impact the project objectives of Scope, Quality, Time and Cost;Quantify the likely impact of each factor;Give a baseline for Project Non-Controllables; andMitigate impacts by exercising influence of Project Controllables.
This paper does not provide a comprehensive specification for a Risk Management program; rather, it is intended to provide the reader with an overview of the general concepts as well as provide sources of additional information for further study. It is also provides real-world examples of what happens when projects experience a breakdown of Project Management and fail to recognize the time and cost impact of relatively small issues, avoidable with a Project Risk Management Program.