bluuebunny/crossref_metadata_2025_split huggingface dataset:
Current Trends and Design Limitations of Subsea Control Hardware
Authors: Beedle Alan , stansfield John 
Published: July 2010

Abstract
The challenges associated with the deployment of subsea hardware used to interface between an umbilical system and subsea production system are greatly compounded when installed in deep and ultra deep water. The challenges are further amplified due to the current trend towards the incorporation of complex integrated foundation structures and the increased robustness of the hardware to account for installation and service loads. Two specific deep water projects are explored within this paper.

Introduction

Umbilicals
Subsea production continues to play an increasing role in the global offshore recovery of oil and gas as extraction moves towards ever deeper water depths and more remote geographical locations. Umbilical systems are critical links in subsea production systems and the impact on hydrocarbon recovery due to total or partial loss of functionality results in a significant loss of revenue for an operator.
An umbilical is a group of fluid conduits (thermoplastic hoses and/or metallic tubes), cables (electrical and fibre optic), power cores either on their own or with combinations of each other, cabled together for flexibility and over-sheathed with an extruded polymer or polypropylene rovings for identification and mechanical protection. Armouring layers can also be added for mechanical strength, impact protection or increased mass for seabed stability or dynamic performance.
Umbilicals can be employed in static or dynamic applications and they are typically used for the control of subsea wells, injection of chemicals, gas lift, data acquisition, telecommunications and electrical power for subsea pumping and separation. Some typical umbilical types are shown in Figure 1.

Umbilical Hardware
Typical items of subsea hardware include Umbilical Termination Assemblies (UTA), Subsea Distribution Units (SDU), Gravity Base Foundation Structures (mudmats), Tether Clamps, Weak Links, Repair Joints and Flying Leads. These hardware designs are typically performed in accordance with DNV Rules for Planning and Execution of Marine Operations(1).
Title Parque das Conchas (BC-10) Subsea Hardware and Artificial Lift Systems - Selection, Challenges and Lessons Learned
Authors: Olijnik Luiz Augusto , La Caze D.A. 
Published: July 2010

Abstract
The ultra-deepwater Parque das Conchas Project, located in the BC-10 block offshore Brazil includes the Ostra, Abalone and Argonauta-BW fields in separate clusters tied back to the FPSO Espirito Santo.
BC-10 is a two-phase project with initial production from Abalone, Ostra and Argonauta-BW. The first phase, now on-stream, includes nine production wells and one gas injection well at water depths around 2,000 meters.
The reservoir characteristics of the first phase of field development dictated the use of six boosting systems on the seabed, four in the Ostra and Abalone fields and two in the Argonauta / B-West field. Each boosting system requires an Electric Submersible Pump (ESP) of 1,500 horsepower providing subsea boosting of up to 2,300psi.
In these ultra-deepwater depths several significant challenges had to be overcome and significant new technology had to be developed to make Parque das Conchas a reality. These include, but are not limited to:The first ultra-deepwater completions deployed through a Surface BOP;A combination of MOBO systems in an artificial lift manifold;The world's deepest subsea MOBO's;First time use of a Heave Compensated Landing System (HCLS) in Brazil;A new world water depth record for subsea hammer operations.
This paper presents the challenges, design, installation and testing of the subsea hardware system, including some of the lessons learned which could benefit future projects in ultra-deep water.

Introduction
Parque das Conchas is located in the BC-10 block offshore Brasil in water depths around 2,000m. Shell Brasil E&P is the operator of the field with a 50% working interest in a joint venture with Petróleo Brasileiro S.A. (Petrobras) and ONGC Campos Ltda. (ONGC) with a 35% and 15% working interests, respectively.
Phase I of the project comprises the subsea development of 3 fields tied back to a centrally located FPSO. In Phase II a fourth field (Argonauta ON) is planned to be tied back (see figure 1).
The subsea hardware installation campaign commenced in Q3-2007 with the deployment of two artificial lift spacer templates and is ongoing at the time of the writing of this paper (Q4-2009).
Field Implementation Of A Real Time Drilling Problem Diagnostic System For Deepwater Exploratory Wells
Authors: Gandelman Roni Abensur , Waldmann Alex Tadeu Almeida , Martins Andre Leibsohn , Teixeira Gleber T. , Aragao Atila Fernando Lima , Rezende Mauricio , de Mari Alexandre 
Published: July 2010

Abstract
This article details the field implementation experience of an in house developed system for drilling problems detection and identification. Starting from real time drilling data (including MWD, PWD and mud logging sources), the system was designed to investigate reasons for deviations in important measured variables (such as downhole and pumping pressures, temperatures, torque and drag, etc.) during drilling operations. Based on a hybrid approach, including multi phase hydraulics and torque & drag modeling, case history matching and specialists knowledge, the system should identify undesirable events, such as influxes, poor solids transport, bit balling, bit wear, drillpipe washouts, hole instabilities among several others.
Field implementation issues includes offshore installations and remote operations from onshore decision support rooms, necessity of team working, requirements for conventional and MPD operations, software calibration and validation challenges and continuous knowledge updating. Examples highlight the benefits on investing in data interpretation and drilling automation technologies for deepwater exploratory scenarios.

Introduction
Deep and ultra deepwater exploratory drilling are very risky and costly operations, in which every effort to guarantee performance and operational safety is welcome. Low frac gradients, abnormal pressures, losses, unstable formations are among the topics which make well design complex and well construction a continuous challenge.
Several exploratory prospects currently ongoing in PETROBRAS faces very narrow or even zero operational windows and well construction will demand non conventional techniques such as MPD or UBD. Figures 1 and 2 show examples about narrow operational windows.
Applications of Multibeam Backscatter: Using Multibeam Echosounder Backscatter to Characterize and Map Seafloor Features in Shallow and Deep Water
Authors: Hewitt Antony T. , Salisbury Richard , Wilson Jerry 
Published: July 2010

Abstract
Recent developments in multibeam echosounder backscatter processing are now included in most commercially available processing software. These tools allow end users to produce properly corrected backscatter mosaics and add more robust qualitative and quantitative discrimination of seabed materials to their seafloor characterizations. This paper reviews backscatter processing and presents some examples that demonstrate the advantages of multibeam backscatter over conventional sidescan sonar. Fully corrected backscatter data increases confidence in interpretations of seabed features, and is an improved baseline data set for implementing automated mapping techniques, which can potentially produce more detailed maps in less time. The corrected backscatter is also more appropriate for integration with sediment samples and subsequent quantitative analysis used in seafloor classification systems. These mapping efforts are of benefit to engineering favorability assessments and other types of seafloor investigations.

Introduction
Both multibeam echosounders and sidescan sonars can be used to collected acoustic backscatter data. Backscatter data is obtained from the reflection of acoustic energy back toward the sonar, where its intensity can be measured. After various corrections are applied, backscatter intensity is essentially a function of the seafloor's physical properties, namely acoustic impedance, roughness (grain-size and small-scale topography), and volume inhomogeneity (variability in the thin layer of sediment penetrated by the acoustic signal). While backscatter from sidescan sonars, developed in the 1950's, has seen wide spread use across many disciplines, a broad base of users is increasingly utilizing the power of multibeam echosounder backscatter for their unique applications. For many years now, fisheries investigators have been utilizing multibeam echosounder backscatter for habitat mapping, and hydrographers have been using it for target detection in shallow water. However, it is only in recent years that it has come into common use in deep-water site investigations for oil field developments. This paper attempts to give a basic review of backscatter processing and presents some examples that demonstrate the advantages of multibeam echosounder backscatter over the more commonly used conventional sidescan sonar imagery.
Qualification of a Semi-Submersible Floating Foundation for Multi-Megawatt Wind Turbines
Authors: Cermelli Christian , Aubault Alexia , Roddier Dominique , McCoy Timothy 
Published: July 2010

Abstract
Recent trends in the wind industry point to the use of increasingly larger and more powerful machines with rated power ranging from 5 to 10MW exclusively designed for offshore use. Floating foundations offer greater flexibility in term of site selection for wind farms, and if properly designed, may result in comparable availability with equivalent offshore turbines on fixed foundations, while reducing the complexity and risks associated with offshore installation.
The WindFloat platform is a semi-submersible platform with three columns fitted with a large horizontal water-entrapment plate at the base. The wind turbine and tower are fitted on one of the columns. The platform is designed to support commercially available multi-megawatt wind turbines with no hardware modification to the turbine. The qualification process followed for the development of a 150MW wind farm offshore Portugal is discussed.
Because of economic constraints, optimization of the platform is essential to achieve project financial targets. A rational and comprehensive process was followed to optimize the system while maintaining the robustness required to survive in the offshore environment. The design process is based on a combination of advanced numerical analysis and scale model experimentation. Full-scale experimentation is ongoing.
Selected design codes and industry standards are applied. The return period of extreme events is adjusted based on experience acquired by the wind industry.
Because of the considerable aerodynamic loads generated by the wind turbine and their effects on platform motion, the ability to solve the combined aerodynamic and hydrodynamic problem is necessary. Additional factors, such as tower dynamics and turbine controls must also be taken into account. Development of a coupled hydro-servo-aero-elastic model constitutes a key element of the qualification process.
Rules for the design of Mobile Offshore Drilling Units are followed to verify platform stability in intact condition, and to ensure that compartmentation is sufficient to withstand damaged conditions with any compartment flooded.
Time-domain coupled analysis of the platform and its mooring system are performed. The hydrodynamic response is also validated with scale model tests.
A four-point mooring configuration is adopted. Reliability considerations are discussed to assess the level of redundancy required in the mooring system, in particular with regards to the one-line damaged condition.
The platform structural design is conducted using applicable offshore codes from several classification societies, as well as extensive finite-element analysis. Structural dynamics is critical to platform design due to the dynamic excitation of the tower and the corresponding loading of the substructure primary members.
API RP 2SIM: Recommended Practice for Structural Integrity Management of Fixed Offshore Platforms
Authors: Defranco Samuel , O&apos;Connor Patrick , Puskar Frank , Bucknell Justin R. , Digre Kris A. 
Published: July 2010

Abstract
API Recommended Practices for the design and operation of GoM platforms have evolved in recent years due to the impact of large hurricanes in the Gulf of Mexico. This evolution of the API offshore practice is based primarily on work performed by the API HEAT Committee, interim API guidelines (e.g., API 2INT-EX), results from updated technology, and the ultimate harmonization of API RP 2A and ISO 19902. This paper summarizes the latest version of the proposed API RP 2SIM (Structural Integrity Management) and clarifies the intent and basis for the proposed revisions to previous draft versions of API RP 2SIM.

Background
API RP 2SIM (RP2SIM) has been the subject of recent papers that clearly explain its overall intent, philosophy, and link to international and existing API practices. In summary, SIM (Structural Integrity Management) is a rational framework for evaluating the integrity of a structure through its entire life cycle. SIM was first incorporated into international practice in the mid-1990s in Draft E of ISO 19902. ISO 19902 was officially published in 2007.
RP2SIM incorporates sections of ISO 19902, API RP 2A 21st Ed. (Section 14 and Section 17) and API 2INT-EX as a basis with a significant expansion in explanation and clarification. RP 2SIM has been organized around the framework of the overall SIM process consisting of Data, Evaluation, Strategy and Program. The main sections of the document are as follows:–Section 1: Introduction, Purpose and Scope–Section 2: Normative References–Section 3: Definitions and Acronyms–Section 4: Structural Integrity Management Process–Section 5: Surveys–Section 6: Damage Evaluation–Section 7: Structural Assessment Process–Section 8: Assessment Criteria and Loads - API 20th Edition and Earlier Platforms–Section 9: Assessment Criteria and Loads - API 21st Edition and Later Platforms–Section 10: Mitigation and/or Risk Reduction–Section 11: Decommissioning
The reader is referred to O'Connor et al. (2005) and Puskar et al. (2006) for further details on each of these sections. RP2SIM will replace the portion of API Bulletin 2INT-EX related to fixed platforms. The original intent of 2INT-EX was an " interim?? guidance document based upon results of the HEAT studies that indicated an assessment was recommended for fixed high consequence L-1 and A-1 structures and floating structures located in the Central Region of the GoM. The Central Region is the location of the largest increase in the estimated extreme hurricane conditions. The " interim?? notation for the EX Bulletin designates that it will be ultimately replaced by other API documents, in this case RP2SIM for fixed platforms. 2INT-EX will be fully replaced once the associated floating structure API documents have been updated to account for assessment, with this work currently underway within API.
SS Metocean / A Synthetic Model for Gulf of Mexico Hurricanes
Authors: Vickery Peter , Wadhera Dhiraj , Stear James 
Published: July 2010

Abstract
This paper describes the development of a synthetic model for Gulf of Mexico hurricanes, for use in establishing design criteria. The model has been derived using atmospheric and historical hurricane data from the 1940's to 2006, and eddy data for the period 1984 through 2006. The influence of sea surface temperature and mixed layer depth on storm intensity is accounted for explicitly. The model is validated by comparing the results of a 100,000-year simulation to historical storm data. Using 300,000 years of storms derived from the model, wind criteria across the Gulf has been estimated for return periods up to 10,000-year, and compared to results from the traditional approach of extrapolating from site-averaged historical data.
This effort represents a step-change in the way hurricane criteria has traditionally been developed by industry. The synthetic hurricane model can improve the stability of hurricane design criteria, and provide more insight to the types of storms which generate rare (1,000- to 10,000-year) site conditions. In addition to offering a more stable basis for hurricane design criteria, the synthetic model also offers the following advantages:Being able to assess the impacts of climate change scenarios such as increasing sea temperature and mixed layer depth, by changing environment parameters and re-generating storms for them.Allowing for a combined hurricane-loop/eddy database, with synthetic storms developed concurrent with synthetic eddies, so that joint hurricane-loop load cases may be better determined.

Introduction
Hurricane design criteria for offshore facilities has traditionally been developed from extrapolations of historical wind, wave and current site data, using a method such as track shifting or site averaging to account for having a limited database and future storm track variability (Toro, et al., 2004). However, industry has long recognized the limitations in the traditional approach in estimating extremes associated with very rare (10,000-year) return periods, and has explored other methods such as deductive modeling to develop improved estimates. Furthermore, the occurrence of very large, powerful storms near a site will affect extremes at the 100-year level calculated using the traditional approach significantly, even with the application of spatial averaging, as was experienced in some parts of the Gulf of Mexico following the addition of hurricanes Ivan, Katrina, Rita and Ike to the historical record. Estimating the potential for combined hurricane-Loop Current eddy (LCE) cases is also problematic, given the even smaller set of LCE data together with an already limited hurricane record. Finally, the traditional approach does not allow for an explicit relation of site extremes back to hurricane climate, making it difficult to project changes in extremes based on changes to the prevailing environment.
Dry versus Wet: An Evaluation of Subsea Tie-Backs and Surface Platform Development Strategies for Nova Scotia
Authors: Dunn Cameron , Rushton Phil 
Published: July 2010

Abstract
The Nova Scotian Offshore has many discovered fields with low quantities of recoverable resources. These marginal fields will need development plans which require lower capital costs than that of standard development. Other areas of the world have also faced similar issues regarding the economics of developing marginal fields. Some of these fields have become economically viable by reducing the cost of the offshore facility and production used to extract and distribute the gas or oil.
This paper presents the results of the evaluation of a case study of a marginal gas field in the Sable Island area of Nova Scotian Offshore. It provides a comparison of the technologies and strategies that would be used to develop the field for a low production rate, including a direct comparison of an exclusively subsea development with that of a minimal Dry Caisson platform development. The comparison includes costs as well as benefits and disadvantages of each development option.
The evaluation results show that for the case study water depth of 40m, the Dry Caisson platform is suitable for use and provides an option for development with a capital cost far lower than the comparable subsea option. Limitations of access, installation considerations and maintenance of both systems are also compared.

Introduction
Currently the Nova Scotian Offshore (NSO) region has many discoveries which could be defined as marginal fields, as shown in Figure 1. Historically, offshore field development for the NSO has used standard large scale and capital intensive infrastructure which would likely be uneconomical for these marginal fields. Minimal platforms and subsea development may provide more cost effective options for future developments.
CO2 injection and storage - qualification of well barriers and adjacent wells
Authors: Vignes Birgit , Enoksen Arne Mikal , Ovesen Monica 
Published: July 2010

Abstract
The Petroleum industry needs a common industry practice related to design of adjacent CO2 injection wells and plugging & abandonment of CO2 injection wells. Adjacent wells are defined in this paper as wells that can be exposed to the injected CO2. A CO2 injection reservoir may be penetrated by a number of adjacent wells that can be potential leakage sources. These wells can be abandoned-, production-, injection- and disposal wells. Adjacent wells can have well integrity issues that can lead to leakage of CO2 to the surroundings. The paper presents some of the potential reservoir- and wellbore- related leakage pathways.
Seismic surveys are performed to verify how the CO2 medium moves within the reservoir. There are identified challenges related to the verification methods of the structural integrity and how the CO2 medium is spread within the CO2 injected reservoir. This can have an impact with regards to the well integrity and degradation of the construction of the adjacent wells.
Carbon dioxide can occur in the liquid, solid or gas phase depending on temperature and pressure. When the pressure containment of a well is lost, the carbon dioxide can have phase changes which can lead to very low temperatures in the wellbore. This paper presents the challenges related to qualification and testing of well barrier elements related to low temperatures and the exposed medium.
The paper illustrates the industry need to further consentrate on well integrity related to CO2 injection wells as well as to the adjacent wells. The control of barrier status is a crucial HSE factor to avoid major incidents caused by i.e. unintentional leaks and well control situations. Knowledge of well integrity status at all times enables the companies to take the right actions in a proactive manner and thereby prevent incidents.