bluuebunny/crossref_metadata_2025_split huggingface dataset:
Biofouling in Marine and Offshore
Authors: Wei Chao 
Published: May 2013

Abstract
This presentation will provide an introduction into internationally and nationally regulated biofouling issues. The risk for spread of invasive aquatic species (IAS) via fouling from ship's hulls / other under water structures or ballast water is being focused upon more and more. IMO issued guidelines in MEPC.207(62) for the control and management of ships' biofouling to minimize the transfer of invasive aquatic species (IAS). The U.S. Coast Guard requires a Biofouling Management Plan be incorporated into, or referenced in, the Ballast Water Management Plan. California is planning to regulate biofouling on ships. Adding to this IAS issue the resistance attributed to biofouling and hull roughness are other important aspects to consider for improving the energy efficiency of a ship's operation and reducing CO2 emissions, which has been reflected in the IMO Marine Environment Protection Committee (MEPC.213(63)) recommendation for a ship energy efficiency management plan (SEEMP).
Considering the above recommendations and requirements, ABS is developing Biofouling Guidance Notes and a Biofouling Management Plan Advisory to assist the shipping industry in dealing with these issues and in complying with the related requirements. ABS Nautical Systems also provides solutions that assist owners and operators in capturing data for demonstrating SEEMP compliance.

Introduction
The issue of hull biofouling has been of concern since floating vessels were first put into the water. In the 1900's many scientists studied the effect of biofouling on ships. Kempf reported in 1937 with an 85% increase in resistance of the ship. In the past few decades of research from R. Townsin, Goeff Swain, M. P. Schultz, and many others on the biofouling effect on ships, have provided enlightening data concerning roughness and bio-fouling contribution to total hull resistance.
Studies by Townsin et al have provided the industry with a scientific understanding of the relationship between hull roughness and resistance. When this relationship is applied in a simplified manner to various types of ships it provides us with good " approximate" values. Because increased resistance is so significant in accounting for the margin of error for each specific ship, such an approximation provides good guidance for how the hull resistance may be better managed.
Many studies have found that a significant portion of coastal invasive aquatic species (IAS) have been introduced via ship hull fouling in addition to those introduced via vessels' ballast water discharges. Consequently the International Maritime Organization (IMO) has developed voluntary guidelines, IMO MEPC.207(62), to minimize the risk of further spread of IAS. In line with the IMO guidelines, some US states have also started the process of making similar guidelines mandatory through laws. The State of California is one such example.
Rigless Intervention: Barriers and Misperceptions About Using Lightweight Intervention Solutions To Increase Oil Recovery from Deepwater, Subsea Wells
Authors: Morrison Bevan , Karlsen Ole Eddie 
Published: May 2013

Abstract
In recent years, the number of subsea wells has increased steadily; a 2011 report estimated more than 5,500 worldwide. One of the key challenges the industry faces with subsea wells is generally lower recovery factors compared to wells with surface access. A key reason for this difference is because workover activities to improve recovery rates in subsea wells has traditionally required use of large rigs, risers, jointed pipe or coiled tubing (CT), with high operating rates. The high costs of these operations can make it difficult to achieve the necessary increases in production rates and revenue to justify the workover investment, even with increasing oil prices; therefore, operators often forgo production-improvement workovers. However, a growing global population and soaring energy demand means that operators are facing increasing pressure to maximize production and value from mature assets.
These challenges have spurred development of alternative, lighter weight, more cost-effective intervention methods to enhance recovery rates in deepwater, subsurface wells. These alternative technologies include electric-line tools that can be run from smaller, dynamically positioned light well intervention vessels, instead of large workover ships with risers. These rigless and riserless light well interventions (RLWI) improve scheduling flexibility and reduce costs, thereby reducing barriers to performing subsurface well interventions and enabling subsea operators to realize oil recovery rates of 50% or more.
Today many industry companies have a clear tendency to migrate towards lightweight, more cost-effective alternative solutions. But for some, misperceptions still exist and skepticism remains for using RLWI for deepwater subsea wells. However, over the past decade, RLWI has achieved a solid track record of demonstrated value and is an inherently safer method for subsea well interventions, compared to conventional heavier methods.
This paper describes the opportunities to improve recovery rates in subsea wells using the lighter, more efficient and ultimately more productive RLWI methods. Using these techniques has enabled operators to conduct routine planned access to subsea producing assets, improve surveillance and management of interventions, and, ultimately, increase recovery rates. Several case histories and examples are presented.

Introduction
Challenge: The Need to Increase Production from Existing Assets to Meet Growing Global Demand for Energy. Looking at peak oil production from a number of the major oil producers shows that many of them have reached peak oil production over the last ten years (Table 1) the industry is striving to find new resources to replace diminishing reserves and to meet increasing global demand; these factors are moving exploration and development into deeper water offshore, where currently more new fields are being developed subsea than from platforms (Strategic Offshore Research Ltd. 2012).
Better Well Control Through Safe Drilling Margin Identification, Influx Analysis and Direct Measurement Method for Deepwater
Authors: Veeningen Daan M 
Published: May 2013

Abstract
Currently, well control events are almost exclusively detected by using surface measurements. Especially in deepwater, where the riser comprises a substantial section of the wellbore, early kick detection is paramount for limiting the severity of a wellbore influx and improves the ability to regain well control.
While downhole data is presently available from downhole tools nearby the bit, available data rates are sparse as wireless telemetry bandwidth is limited and wellbore measurements compete with transmission of other subsurface data. High-bandwidth downhole data transmission system, via a wired or networked drillstring system, has the unique capability to acquire real-time pressure measurement at a number of locations along the drillstring.
The paper describes the four processes to improve well control for deepwater operations through the use of downhole data independent from surface measurements. First, networked drillstring provide efficient kick detection and the identification of ballooning zones. Gas inside the riser is also detected and decision support is offered between using the mud-gas separator or diverter. Second, a methodology is proposed using direct measurement of downhole real-time pressure for maintaining constant bottomhole pressure during well kills in deepwater. Third, downhole surge and swab pressures are available through measurement while tripping system. Fourth, well control barriers are verified using downhole information, independently from surface data. All of these workflows allow for higher levels of automation, supporting wellsite personnel and improving the safety of operations. The paper presents examples of field data that illustrate these cases.
Response and Simulation of the Pipe-in-Pipe System in Free Spans
Authors: Giagmouris Theofilos , Tang Andy , Qi Xinhai , Zhong Jianxia 
Published: May 2013

Abstract
The interest in the numerical modeling of a deepwater pipe-in-pipe system (PiP) at a free span location is growing. In a free span, the inner pipe bends substantially due to internal pressure and temperature and possibly contacts the outer pipe. Concerns arise how the interaction between them affects the PiP behavior under thermal expansion and contraction. The study is motivated by the need to understand how a PiP at a free span can be modeled adequately. Different finite element (FE) approaches using Abaqus have been practiced. The pipes were simulated with pipe, elbow, and shell elements. The interaction between the inner and outer pipes was simulated with multi-point constraints (MPC), tube-to-tube contact elements (ITT), and contact surfaces. FE model accuracy and cost effectiveness were compared in a case study. The conclusions in this paper would also be applied for PiP sections with bending, such as for lateral buckling of a PiP laid on the seabed and upheaval buckling of a buried PiP.

Introduction
A PiP insulates the inner pipe using an outer pipe as shown in Figure 1(a). In a free span, Figure 1(b), the pipes bend and the gap between them allow for relative displacement due to different effective tension and weight of the pipes. A shell FE model of a PiP at a span was developed to investigate the behavior during operating and cool down conditions. In addition, pipe FE models were developed and evaluated against the shell element model. It is shown that while the shell FE model simulates the motion of the inner pipe relative to the outer pipe and the contact between them, it requires a lot of computational effort. Contrary, a pipe FE model provides global deformation and pipe stresses close to those of the shell FE model and is cost effective. Table 1 and Table 2 summarize the PiP properties, span under investigation, and loading conditions for each pipe.
Practical Experience Gained Operating a Compact Ultradeepwater Drill Ship
Authors: Deul Hans , van den Broek Leon , Wijning Dieter , MacKinlay Walter Malcolm , Roodenburg Joop 
Published: May 2013

Abstract
This paper describes the practical experiences gained during the first year of operation of a new Panamax-size ultra deepwater drill ship. The vessel started operations in the Gulf of Mexico in July 2012. The practical experience is offset against the vessel's design expectations: improved safety, an increased drilling efficiency and reduced operational costs.
The drill ship is of an integrated design covering vessel, drill tower and equipment handling. The drill ship offers an equal payload compared to other ultra deepwater drill ships but at half the displacement. This paper details the effects of the highly automated onboard material and equipment handling on the vessel's drilling efficiency and on the operational cost
The material and equipment handling is designed around the box girder drill tower that has no V-door limitation and features a drilling side and a construction side, thus minimising flat time. Stands built on one side of the tower can be stored in two set back drums, one on each side of the tower, and taken out when needed. Four pipe handlers are available for handling purposes.
This paper covers the field experience with all features of the drill tower that are designed to save time and/or increase efficiency and/or enhance onboard safety. These include the drill tower's dual drawworks eliminating slip-cut procedures, the passive and active heave compensation on the drawworks, and the splittable blocks. The latter allow increasing the block speed for lighter loads.
Dry Tree Semisubmersibles for Gulf of Mexico
Authors: Rijken Oriol , Leverette Steven J , Bian Xiaoqiang 
Published: May 2013

Abstract
The offshore industry has expressed a desire for combining production activities with drilling activities on semisubmersible platforms with the wellheads on the platform. This combination of activities allows for an earlier start of production while the drilling program is ongoing and/or allows well maintenance to be performed during production. These systems are typically referred to as dry tree semisubmersibles. Drilling semisubmersibles are successfully operational around the world and production semisubmersibles with subsea wells are operational in the Gulf of Mexico, the North Sea, and offshore Brazil. However, a dry tree semisubmersible solution for hurricane environments that is both technically and economically viable is in various stages of maturity. The challenge for these structures in hurricane environments is the magnitude of the stroke of the top tensioned risers (TTR) which is significant, and but is now within proven technology used on deepwater semisubmersible drilling rigs.
This issue can be resolved technically by either reducing the vertical motion of the semisubmersible, by increasing the allowable tensioner stroke, or by a combination of both. An evaluation and discussion is provided on both solution paths with a focus not only on the technical challenges but also on the cost aspects of the proposed solution paths. Cost is affected by the tensioners, construction, integration, transportation, and installation issues. This paper will present one solution to the design challenge of a dry tree semisubmersible in hurricane conditions, and the resulting compromises will be discussed.
The dry tree semisubmersible has promise to be more cost effective than spar or TLP solutions in many development scenarios, and will be an important component in developing ultra-deepwater reservoirs.

Introduction
The offshore industry has approached deep water oil and gas production with a mix of wet tree (subsea) and dry tree systems. Wet tree solutions typically have remote subsea wellheads/trees which are located away from the vessel and which are connected to the vessel by means of steel or flexible catenary riser systems, while the dry tree systems typically are positioned directly over the well locations so that the well is extended to the surface with a top-tensioned riser. The wet tree systems include all variations of floating vessels, including FPSO's, semisubmersibles, TLP's, and simple barges. The currently installed dry tree solutions are limited to TLP's and spars.
Simulation Technology To Assess ROV Operations at an Early Planning Phase
Authors: Laroche Sylvain , Dawes Daniel , Cohan Steve , Moore Brian , Rodsand Espen 
Published: May 2013

Abstract
This paper documents the use of Vortex simulation technology and vSIT methodology used for the design of the subsea production system (SPS) for the Laggan-Tormore gas condensate fields west of Shetland. Subsea operations in these extreme weather conditions are very technically challenging, and simulation tools have been developed for verifying full and safe ROV access and operability throughout SPS development.

Introduction
This paper documents the use of Vortex real-time dynamics simulation as part of the detailed design of the subsea production system (SPS) for the Laggan-Tormore gas condensate fields west of Shetland. The two fields are developed and operated by Total E&P UK Limited along with its joint venture partner DONG E&P (UK) Limited. The SPS, situated at 600 m (1,968 ft) water depth, is designed and procured by FMC Technologies. It includes two 6-slot Template Manifolds, one Satellite Well Protection Structure and 9 Subsea Trees (XT), and is very technically challenging due to extreme weather conditions. To be able to verify full and safe ROV access and operability throughout SPS development, Total commissioned the use of a ROV simulator. This resulted in CM Labs, FMC Technologies Schilling Robotics and FMC Technologies combining to develop a desktop software ROV simulation tool. Examples of simulated operations include umbilical end termination and well jumper installation, XT installation and subsea control module change-out. Thirty-seven operations have been simulated on two working sites of the Laggan-Tormore fields (one Template and one Satellite) in order to verify planned operations from an engineering perspective, including analysis of custom equipment design.
By simulating interventions using state-of-the-art simulation software, we were able to allow ROV operators to interact with the simulated environment (as opposed to preset motion planning). Simulating the dynamic interactions between the ROV, ROV tooling and the subsea equipment enables understanding of operations beyond what is achievable with purely kinematic animation. This has the considerable benefit of giving the project team an early opportunity to assess any issues that may be encountered as part of the offshore installation campaign. This approach allows the ROV operator to evaluate the potential for unforeseen impediments that may cause unnecessary delay, or at worst render the operation unfeasible. Being able to assess the installation operations before the physical interface check is completed during the traditional Site Integration Testing (SIT) also allows the equipment provider time to make any required design changes before manufacturing is completed. In order to support this process, a workflow has been implemented, encompassing procedure descriptions, storyboards, mission recordings, and reporting of discovered issues. This workflow enables iterative refinement of the simulation results and a pipeline of work output.
Development and Production of Cascade and Chinook Fields in the Gulf of Mexico: An Overview
Authors: Mattos Deborah M. , Palagi Cesar L. , Ribeiro Orlando J. S. , da Matta Jr. Salvador 
Published: May 2013

Abstract
This paper is based on the work performed during the design, implementation and operation of the Cascade and Chinook fields, located offshore the United States Gulf of Mexico (USGoM) - the first deployment of an FPSO in the region. It presents an overview of the reservoir rock and fluid properties, the design and construction of wells, the design and installation of the subsea system and FPSO BW Pioneer, the oil export system through shuttle tankers, the gas export through pipelines and the regulatory framework of the project. It also presents operational information about the first wells on stream in each field.
The information provided in this paper is a useful reference for petroleum field operators when designing development concepts for ultra-deep water discoveries, not only in the USGoM but also worldwide. It is especially useful for the design of field development and early production systems located far from pipeline infrastructure. It is useful for contractors to identify the technologies which are most suited for application on deep wells and ultra-deep water subsea systems and production platforms.
The initial phase of development, already implemented, consists of two subsea wells in Cascade and one in Chinook tied back, through a field-specific subsea system, to a Floating, Production, Storage and Offloading (FPSO) platform. Oil is transported from the FPSO in shuttle vessels to terminals of opportunity along the USGoM and gas is exported through pipeline. Wells started-up production in 2012. Future phases of development will depend on the performance of the wells.
Cascade and Chinook Subsea Development: A Challenging and Successful Case History
Authors: Cassity Thomas Gus , O'Donnell Michael , Weigle John , Masson Craig , Kochi Kazuhiko , Porciuncula Sergio L. 
Published: May 2013

Abstract
This paper is based on the subsea work performed during the design, implementation and operation of the Cascade and Chinook Field Development Project in ultra-deep waters of the U.S. Gulf of Mexico (USGoM). It describes the engineering, procurement, construction, installation, operation and integrity management phases of the subsea production system. This project required several innovative technologies and solutions that resulted in several " firsts" and records for the industry: first of a kind and deepest subsea boosting system with ESP-Electric submerged pumps installed on the seabed at 8800 ft, non-conventional power umbilicals utilizing carbon fiber rods as the principal tensile strength elements, first subsea pull-in of umbilicals utilizing a submerged winch, deepest and highest pressure rated Free Standing Hybrid Risers (FSHRs), deepest pipe-in pipe flowline and deepest gas export pipeline. This case history paper also describes the procurement strategies employed and the project management systems adopted to mitigate technical, time and cost risks.

Introduction
The C&C fields are located in the Walker Ridge Outer Continental Shelf (OCS) leasing area of the central USGoM. Both fields are situated near the base of the Sigsbee Escarpment on the abyssal plain of the USGoM in ultra deep water. Cascade is located about 160 miles south of the Louisiana coast in 8,200 ft water depth and Chinook is about 15 miles due south of Cascade in 8,800 ft water depth.
The Cascade discovery was made in 2002 and Chinook was discovered in 2003. The C&C reservoirs are in the Lower Tertiary (Wilcox) Ultra-Deepwater trend. After appraisal work the C&C was sanctioned in late 2007 based on a phased development concept. The initial project phase, the subject of this paper, is an early production scenario based on a limited number of wells and subsea infrastructure and the purpose of this initial phase is to gain reservoir information in order to optimize future development phases. The initial phase utilizes a leased, disconnectable, floating, production, storage and offloading (FPSO) vessel located between the fields. Produced oil is transported from the field in shuttle vessels and gas is exported through an export pipeline. The main reason for selecting the FPSO was safety, primarily with respect to hurricanes. The detachable turret mooring buoy provides a mooring point for the FPSO and during the approach of a hurricane the buoy enables the FPSO to disconnect in a short period of time in order to depart the area.
Future phases increase the amount of producing wells and subsea infrastructure and a definitive optimized permanent production facility is to be installed in the last phase. Decisions on the type of and design basis of a definitive facility and number of wells will be finalized in 2013 and 2014.