bluuebunny/crossref_metadata_2025_split huggingface dataset:
Evaluation of Wellhead Fatigue Using In-Service Structural Monitoring Data
Authors: Rimmer Alex , Howells Hugh , Ward Phil 
Published: May 2013

Abstract
To conduct offshore drilling activities safely there is an increasing requirement to understand the strength and durability of subsea wellheads and conductors. The use of modern drilling rigs, with larger BOP stacks and drill-through trees, combined with longer well durations and multiple intervention operations is now producing far greater levels of fatigue loading on subsea wellheads.
The prediction of the fatigue response using numerical analysis has traditionally taken a conservative approach to mitigate against the risk of fatigue failure of the drilling riser and wellhead equipment. However, using this conservative approach, the allowable fatigue design limits are often predicted to be exceeded before the target operation durations are achieved. This can lead to costly last-minute design changes, the necessity for which often remains unproven.
To improve the understanding of the fatigue behaviour of these systems, 2H has utilised in-situ monitoring of the drilling riser and wellhead response on recent projects in the Gulf of Mexico and the North Sea for a number of Operators. Wellhead fatigue life predictions, for which minimal in-service validation has traditionally been available, have been found to be conservative by factors of 10 or greater based on the field measurement data collected. Understanding the root causes of these levels of conservatism allows a critical view to be taken of analytical models and fatigue results. This in turn facilitates the safe removal of conservatisms from the analytical approach and associated cost savings for field operators. Further, in-situ monitoring allows management of fatigue during drilling with real-time tracking of fatigue accumulation providing feedback for safer planning of operations.
This paper describes the use of wellhead response monitoring programmes on a recent drilling campaign in the North Sea. Comparisons are drawn between the measured response and the analytically predicted wellhead fatigue results. Where differences are identified, the back-analysis activities conducted to identify the causes of those differences are discussed. Finally, the applicability and limitations of those findings for the refinement of wellhead fatigue predictions in other applications are outlined.
Minimizing the Risk of Coating Failure
Authors: Kattan Raouf 
Published: May 2013

Abstract
Through life costs are often dictated by the ability to minimise corrosion, in particular in splash zones or ballast tanks. Coating system failures on some offshore structures/vessels are not only expensive but have created concerns for through life maintenance and repair as they could possibly increase the risk of assets coming off-stream as a result of failure as well as having an adverse impact on the cost of any life extension programme.
The proper selection of a coating system is critical to the effective operation of the structure/vessel and should therefore be engineered as an integral solution, rather than left to chance. Owners/operators are often misled by considering only the total thickness of steel rather than the corrosion allowance that is built in. it is this corrosion allowance that the coating system must be engineered to protect.
All owners of offshore structures want a structure/vessel that meets requirements for through life performance. Coatings play an increasingly important role not only in maintaining asset value but also ensuring in service performance sustaining the income stream by preventing corrosion, fouling, enabling various chemicals to be handled and keeping the cosmetic appearance of the structure in line with corporate image requirements.
Vessel design if considered at an early stage, could contribute significantly to increasing the throughlife performance of coatings while the proper selection of coatings whether for anti-corrosion, fouling prevention, cosmetic appearance and specialist tanks, is critical to the effective a low cost operation of the structure through life.
Combining Contemporary and Tested Technologies to Achieve Successful Deepwater Extended Reach Completions
Authors: McCarty R. Andrew , Broderick Mike , Brister Ray , Stewart Mike 
Published: May 2013

Abstract
Many technologies on the market today are considered contemporary or modern such as Inflow and Injection Control Devices (ICDs), especially when used with screens, tracers, and swell packers. Tested technologies include extended reach drilling in deepwater environments.
This paper details the design, planning, and execution of completions from a tension leg platform in just such an environment. A baseline completion consisting of ICDs, stand-alone screens (SAS) and swell packers was initially selected. The selection process involved technical evaluations on types of ICDs, injection vs production screens, filter medias, length, type, and materials for swellable packers, all of which were not only evaluated in combination with each other but also their feasibility and utilization in deepwater extended reach applications.
Managing ECDs and riser vibrations, torque and drag, uniform inflow and outflow distribution, effective sand control, tracer tracking, etc., are all good technical search topics unto themselves. But this Indonesian deepwater project combines them all resulting in positive design, cost, time, production, and execution metrics in multiple production well projects.
Lessons Learned Registers were carried from well to well resulting in significant Non-Productive Time (NPT) reductions of initially 30–40% from baseline benchmarks and acknowledged international databases with further reductions resulting from the applications of the lessons learned and best practices implemented.

Introduction
This field was the first deepwater development in Indonesia. It lies at a water depth of approximately 3,000 ft offshore of East Kalimantan. The field development, on production since 2003, consists of a Tension Leg Platform (TLP) with 28 dry tree wells, a floating production unit (FPU), and two 60 km export pipelines (12 " oil and 12 " gas) to shore. The Extended Reach Drilling (ERD) Project comprises four producers reaching outlying reservoirs that have proven undeveloped reserves from previous delineation penetrations. The reserves lie at extended reach drilling ratios of 1.5 to 2.5, just beyond conventional drilling envelopes used to drill the 28 existing development wells. Actual well names were changed for this paper to Wells A, B, C, and D.
Evaluation of the Hydrolysis Behaviour of PA in High-Pressure CO2 Environments
Authors: Buchner Stefan , Clevelario Judimar , Sheldrake Terry , Pires Fabio 
Published: May 2013

Abstract
In the latest offshore developments to be carried out in Brazil, supercritical CO2 (scCO2) injection into the fields is being considered as a potential application. This injection operation will gradually lead to high levels of CO2 in the produced fluids, creating additional challenges for the materials used in riser systems specifically designed for such applications. Upcoming developments are being carried out in ultra-deep waters which can reach 2500 m. Flexible pipes are considered one of the options for both production and CO2 injection pipes due to performance in such scenarios and fast implementation when compared with conventional rigid riser systems. However, the high levels of CO2 and the presence of water in the conveyed fluids has raised some questions about the utilization of polyamides in such applications, and the applicability of API 17 TR2 to properly predict the hydrolysis of polyamides in such extreme environments. Based on this new scenario, GE Oil & Gas has implemented a specific R&D program to evaluate the hydrolysis behavior of polyamides within environments containing high CO2 partial pressure, exceeding 400 bar. This paper summarizes the experimental results assessed during the test program carried out and discusses the applicability of polyamides in both oil/gas production and CO2 injection flexible pipes.

Introduction
Though CO2 reinjection into geological formations is not a new subject, in recent years its importance has gradually increased within the offshore industry, due mainly to adoption of carbon capture and storage (CCS) and enhanced oil recovery (EOR). The feasibility of offshore reinjection operations was demonstrated in 1996 with the development of the Sleipner field in Norway as part of a CCS project [1], and again in 2004 in Algeria with the development of the In Salah natural gas field [2] with approximately one million tons of CO2 per year being separated from the produced natural gas and then reinjected into the geological formation. In order to make CCS cost effective and economically feasible, the CO2 reinjection may be used as part of an EOR process to improve production and fight reservoir depletion [3]. The need for CCS is even greater in the development of offshore projects in the Brazilian pre-salt cluster in ultra-deep water, an environment with several technological challenges. According to Nakano [4] the produced oil in this new exploratory province will present a high gas : oil ratio (GOR) and the dissolved gas will present a CO2 concentration ranging from 8 to 12% during the first years of production. Based on this scenario, CCS and EOR programs will be put in place [4] [5] to comply with environmental regulations and make the project more cost effective.
Comparison of Seafloor and Shallow Stratigraphic Conditions Mapped From 3D Seismic and AUV Data at Two Deepwater Areas, Keathley Canyon, Gulf of Mexico
Authors: Scherschel Craig , Thomson James A. 
Published: May 2013

Abstract
This paper presents results of an integrated interpretation effort to understand seafloor and shallow stratigraphic conditions at drill sites within two prospective areas in a deepwater portion of the northern Gulf of Mexico. Datasets of different resolution were utilized, including AUV multibeam echo sounder data. These highest resolution AUV data were collected early in the life of the two projects to assess seafloor conditions. In one instance, the AUV data were acquired to comply with newly issued governmental regulations for archaeological clearance studies. As an added benefit, the required AUV data also provided a clear view of potential seafloor geological constraints giving BP and co-owners early insight into factors such as chemosynthetic community indicators, seafloor expulsion features and hardgrounds. These insights will be used and further developed throughout the life of the projects, affecting work not only during early exploration, but also in an exploration success case, through appraisal, development and into production phases as a baseline survey.
The primary purpose of this case study was to learn how geophysical data collected at different resolutions during subsequent project phases could be leveraged to efficiently discern potential constraints to operations resulting from geological processes affecting seabed and near-surface stratigraphy. Additional insight came from a comparison of geological conditions at the two sites. These conditions were similar at the nearby sites but key differences were noted.
The steps followed may define a multiphase approach that efficiently uses site survey results and supports early acquisition of detailed site investigation data. In addition to obtaining detailed site investigation data early on, it is shown that obtaining more than the minimum coverage area needed to clear the initial exploration locations in a prospect has the added benefit of providing broader geographic understanding of seafloor conditions away from the prospect center, revealing potential constraints that would affect appraisal and development locations while reducing or eliminating the need for subsequent surveys.
A comparison of conditions at the two prospects showed similar geological settings and highlights the different needs for high-resolution site investigation data at different stages of a field development, not just during the development phase, as has been practiced previously. Results of the site investigation evaluation have been incorporated into planning of wellbore trajectories at prospects in the Keathley Canyon protraction area and in documents submitted to comply with regulatory requirements of the Bureau of Ocean Energy Management.
Analyses of SCR with Pull-Tube Using ABAQUS and Flexcom
Authors: Liu Hugh Y , Wang Kevin , Yiu Flora 
Published: May 2013

Abstract
Pipe-in-pipe analyses of in-place SCR (Steel Catenary Riser) within pull-tube (PT) or pull-in analyses of SCR through PT are computationally complicated problems in offshore development in the application of SCR hanging off through PT from a platform such as Spar. In the past, those analyses have been done primarily using ABAQUS, an advanced nonlinear FEA commercial tool. A benchmark study of pipe-in-pipe analysis, i.e. SCR through PT, was conducted to compare the performance of ABAQUS and Flexcom, a package popular in the offshore oil and gas industry dedicated to flexible structures like risers or mooring lines. Both static and dynamic loading conditions, as well as the pull-in process were included in the paper. Bending moment, tension, shear force, and von Mises stress of both SCR and PT were compared.
The comparison shows that Flexcom pipe-in-pipe analysis of in-place SCR within PT or pull-in analysis of SCR through PT can obtain satisfactory results in bending moment and stress for both static and dynamic simulations with close agreement with ABAQUS. While the friction between SCR and PT is not accounted for in Flexcom, its effect is mainly on tension especially of PT, and insignificant for bending moment and bending stress, which governs the strength and fatigue performance of both PT and SCR at the upper hang-off region.
This study indicates that it could be adequate to use Flexcom to conduct pipe-in-pipe analysis with much better efficiency for analysis of in-place SCR within PT or pull-in analysis of SCR through PT.
Determining the Cause of Osmotic Activity in Paint Films and Its Role in Substrate Corrosion
Authors: Mills George 
Published: May 2013

Abstract
The process of osmosis is a natural phenomenon involving the movement of SINGLE small molecules through a " porous or simi-permible " film. The skin of tomatoes will crack after swelling from moisture ingress. Pickles will shrink as moisture is lost from a cucumber soaking in brine. ALL polymeric organic films are subject to small molecule migration within the film. This WILL occur to varying degrees dependent on factors such as the polarity of the migrating specie, degree of cross-linking of the polymer matrix, temperature, amount of formulated inert mineral fillers, and a myriad of other factors. Osmotic activity in polymeric paint films is a common coating failure mode. Corrosion of the metal substrate, typically, will follow if not protected by an active cathodic electrical potential, chemical additives, or other means.
Osmosis involves the transmission of single molecules through the matrix. As such, since the definition of a gas is " a collection of single molecules ", osmosis is a gas phase transmission and follows the General Gas Laws. An understanding of the process of osmotic activity in paint films will assist the practitioner in determining the source that drives the osmosis and in analyzing the paint failure.
Osmotic activity in paint films is explained and the analytical procedures and instruments used to identify its driving source(s) are discussed. Osmotic activity requires a solvent and solute. Not all solutes are introduced during application or manufacturer of the coating. While some are present at or during application, some are generated insitu from chemical reactions during service. The source and chemistry of some of these are discussed. Cathodic protection (CP) generates hydroxyl ions that cause additional osmotic activity. Fermentation of sugars generates acetic acid that can lead to osmotic activity in tank linings.
Empreinte: New Horizons for Pipelines Integrity Assessment
Authors: BERNARD Michel , FONTANABONA Julien , GAFFARD Vincent , POPINEAU Dominique , WIET Paul 
Published: May 2013

Abstract
Integrity assessment of pipelines exhibiting defects becomes more and more an issue in the oil and gas industry in particular because of field lifetime extension. Three levels of defects assessments can be distinguished:" Level 1 " assessments are based on very simplified acceptance criteria such as a dent depth. They are very conservative and their main advantage is to allow assessments in very short time period." Level 2 " assessments are based on analytical/empirical models supported by full scale testing. In principle, they cannot be used outside the conditions covered by full scale tests." Level 3 " assessments are based on advanced calculations such as finite elements. They allow reducing conservatisms but they need detailed material data and are, in general, very time consuming.
The goal of " Empreinte " is to perform reasonably conservative " level 3 " assessments in a very short time period (typically within 48 hours from defect discovery to assessment).
" Empreinte " is basically a pre and post processor to Abaqus finite element calculations. It was originally developed to assess the integrity of pipelines exhibiting severe dents with taking into account that when a dent is discovered, the only available information is, most of the time, the actual pipe geometry (defect profile and remaining wall thickness).
The principle of " Empreinte " is to use the final pipe profile to design back a " virtual tool " from which the damaging process is modeled. Then, the burst strength of the damaged pipe is determined from finite element calculations. This actual burst strength is used to derive a safe operating pressure.
" Empreinte " validation is supported by full scale tests in various conditions. It includes criteria to capture failure by plastic collapse and by ductile fracture after significant damage development. " Empreinte " has been recently extended to the assessment of dents submitted to cyclic loading conditions using the Dang Van criterion.
The enlargement of " Empreinte " validation tests database has to be a continuous effort. Updating materials data requirements for next pipeline projects is also a target.
" Empreinte " has already been successfully used. " Empreinte " can be used for design purposes (risk assessments) or for integrity assessments.
Qualification of New Polyamide for Flexible Flowlines and Risers at Elevated Pressure and Temperature
Authors: Chollet Camille , Do Anh Tuan 
Published: May 2013

Abstract
The thermoplastic layer which provides containment for the conveyed fluid in a flexible pipe is designed according to two main parameters: internal pressure and temperature. Up to now, for moderate and high pressure (typically above 5000 psi), only two main grades of polymer are used: PVDF and Polyamide 11. This last one has a maximal using-temperature limited by its resistance to hydrolysis when in contact with water: for example, this ageing issue decreases the maximum accepted operating temperature down to 60°C in the presence of acidic water for 20 year usage. Thus, until now, for this kind of application and a required temperature higher than 60°C, only PVDF could be chosen as pressure sheath.
In order to propose a material, more cost-competitive than PVDF in this temperature range, Technip has qualified a new thermoplastic polyamide for pressure sheath application. Beyond its excellent ductility at low temperature, its blistering behavior up to 15000 psi and its good chemical resistance peculiar to polyamides, it presents a great improvement in terms of hydrolysis resistance; this has been made possible thanks to a special chemistry enabling its use up to 90°C in presence of water. This temperature limit has been established thanks to an extensive experimental ageing study.
The qualification work of this innovative polyamide has covered several large scale industrial extrusion trials as well as a full set of laboratory tests (including those required by API 17J) and different tests on prototype flexible pipes. The paper will present the technical advantages of this new high-performance polymer and the work performed to qualify it for both static and dynamic pressure sheath applications.
A Historical Review on Integrity Issues of Permanent Mooring Systems
Authors: Ma Kai-tung , Shu Hongbo , Smedley Philip , L&apos;Hostis Didier , Duggal Arun 
Published: May 2013

Abstract
With several incidents occurring between 2001 and 2011, the relatively high failure rate of permanent mooring systems is raising a concern in the offshore industry. As a response to this, the paper summarizes various incidents and reviews their failure mechanisms and associated integrity issues. In summary, at least eight (8) incidents involved multiple line breaks; some of them leading to vessel drift. Many more with a single-line breakage were accompanied by similar damage in other lines. Many line failures occurred in their early lives, showing a trend of " infant mortality." Chain, connector and wire rope appear to be the top three components that caused most incidents. Several incidents came as a surprise to industry experts. One particularly surprising finding is the novel nature of the failure mechanisms of some incidents, such as out-of-plane bending, chain hockling/twisting, flawed flash welds, low metal toughness, pitting corrosion, etc. Unknown or new failure mechanisms are troubling because, since they are unanticipated, they cannot be easily detected and prevented with existing integrity practices. This paper critically examines the practices, discusses their limitations and identifies possible improvements, while also highlighting future challenges. To raise the bar for the future reliability of mooring systems, some planned improvements on design codes, taking API Standards as a model, are proposed. A key advocate from the authors is to build a healthier industry by more formally sharing lessons learned, so similar failures can be prevented and mooring integrity can be improved.

Introduction
In the past decade, mooring incidents have been occurring at a high rate. More than twenty (20) incidents have happened to production vessels that are moored on-site for prolonged duration (typically 15–25 years). Among those, at least eight (8) had multiple line damages, or system failure. Some of them led to vessel drifting. Furthermore, the incidents with single-line breakage often have additional lines that sustained damage and could have also failed prematurely if their degradation went undetected. Some of the incidents were of high consequence, causing the vessel to drift a short distance, riser ruptures, production shutdown and small amount of hydrocarbon release. Some were of substantial consequence, requiring effort to repair or replace damaged lines. These incidents are raising concerns for owners and operators. It is important for the industry to better manage mooring integrity and reduce the number of incidents.