bluuebunny/crossref_metadata_2025_split huggingface dataset:
Hydrate Prevention in Subsea Oil Production Dead-Legs
Authors: Cai Jing Jing , Abedinzadegan Abdi Majid , Hawboldt Kelly , Sundgaard Candice , Haghighi Mohammad 
Published: May 2013

Abstract
A study was conducted to better understand the hydraulic and thermal behaviour of dead-legs within a stacked spool arrangement designed to produce two well streams from a single manifold. The study included scenarios under different rigid spool orientations and active line flow conditions. The ultimate goal of the study was to optimize inhibitor injection procedures with respect to loss of inhibitor and contamination of the production fluids.
A Computational Fluid Dynamics (CFD) technique was employed to simulate the flow and thermal conditions within the flow lines and dead-legs. The results of the simulations were validated with two sets of experiments and in two different scales (sizes). The findings of the study suggest that the thermal and/or hydraulic status of the dead-legs during long shut-in periods pose little risk of hydrate formation.

Introduction
A dead-leg is defined as an inactive portion of the pipe where the flow is stagnant or has very low velocity. This inactive pipe is normally connected to an active pipe that carries the main flowing stream. Due to the low or stagnant flow created in dead-legs, there is a risk of cool-down and hydrate formation. The stagnant conditions within the dead-legs could also promote corrosion.
The formation of hydrates is a well known phenomenon in the oil and gas production and processing systems. Hydrates can form under low temperature and high pressure when water is present in contact with gaseous or live crude oil and light liquid hydrocarbons. The fluids present in the well-stream contain a certain amount of gas which is saturated with vaporized water. Free produced or condensed water can collect in the low-points of the pipeline including pipe segments within dead-legs. Hydrates can be formed as a solid block when the line is left inactive and can potentially plug the pipeline.
When hydrate formation happens, the hydrate plug in the pipeline may be either removed by depressurization or injection of inhibitor. By depressurizing one or even two sides of the plug, the hydrate plug starts to melt and can potentially move with high velocity, which could cause severe damage to subsea components. The formation of hydrates in the rigid spools connecting the subsea trees to the main subsea production manifolds could result in complex consequences. The manifold-subsea tree interconnecting spool is connected to the manifold from one side and can be relatively easily depressurized; however the tree side of the spool cannot be depressurized readily and may require costly subsea intervention and an extended loss of production. Addition of hydrate inhibitor will reduce the melting temperature and reduce the thermodynamic potential for hydrate formation. Flushing dead-legs with inhibitors such as methanol can protect them from hydrate formation during shut-in periods.
Control of the Integrity of Swaged Weld on Insulated Pipe-in-Pipe
Authors: Mallik Ajit , ATIN Cesar , Wang Jue , Deleye Xavier , Legras Jean-Luc 
Published: May 2013

Abstract
In typical insulated Pipe-in-pipe (PIP) systems, both extremities of the outer jacket pipe are swaged down close to the inner pipe and are welded directly to the outer surface of the inner pipe. This full penetration weld (hereafter called swaged weld) works as a structure connection between the inner and outer pipes and seals the annulus between the two pipes. The integrity of this swaged weld ensures the structure integrity of whole PIP as well as its thermal properties.
The non standard geometry of this swaged weld presents a real challenge for its Non Destructive Examination (NDE). Despite of its long existence and its importance, the inspection of this swaged weld has always been performed by Manual Ultrasonic Testing (MUT) or Semi Automated Ultrasonic Testing.
This paper presents an Automated Ultrasonic Testing (AUT) system recently developed to inspect this type of weld more efficiently and more completely. The principle of this system and its Det Norske Veritas (DNV) qualified performance in term of defect detection capability and sizing accuracy will be described.
To enhance the integrity of the inspected welds, fitness-for-purpose acceptance criteria have to be developed for this AUT system. Due to the range in weld geometry, the analytic approach conventionally employed for girth welds is no longer applicable. A Finite Element Analysis (FEA) based on Engineering Critical Assessment (ECA) approach has to be applied and this approach will be presented.
In a recent West African SURF project, this AUT system coupled with fitness-for-purpose acceptance criteria has been applied with success.

1. Introduction
Developments of the high temperature high pressure (HTHP) field bring on stage more strict requirements on thermal insulation of the pipelines. Conventional wet thermal insulation such as 5-layer polypropylene foam (5LPP foam) or 5-layer syntactic polypropylene (5L syntactic PP) turns out to be limited both in terms of the insulation efficiency (U value over 1.5W/ m2.K or 0,264BTU/hr.ft2.°F) and the maximum service temperature (approximately 130°C or 166°F). The Pipe-in-pipe (PIP) system presents a good alternative where conventional wet thermal insulation is not applicable. A typical PIP system can provide U value down to 0.5W/ m2.K or 0.09BTU/hr.ft2.°F, which extends the cooling down time of the pipelines and reduces the risk of hydrate formation and waxing during shutdowns and start ups.
PIP systems were introduced to the fields inWest Africa more than a decade ago. The first typical PIP system was installed in Tchibeli field; one PIP production line, with a length of 25km, was installed in 1999. More recently such system was installed in several other fields such as Bonga and Kizomba Satellite.
Contractors: A Help or Hindrance to Your SEMS Program
Authors: Carmichael, MS, CSP Pisces 
Published: May 2013

Abstract

Application
The new regulatory era for offshore oil and gas exploration and production in the United States Outer Continental Shelf (OCS) is still evolving and requires operators to take a hard internal assessment of how they stand against current US regulations like Title 30 Code of Federal Regulations (CFR) 250, Subpart S- Safety and Environmental Management System (SEMS).

Results, Observations, and Conclusions
The SEMS regulation has created a combination of interest, anxiety, and uncertainty within the upstream industry. Recent BSEE district investigation data shows that contractors are an important factor in incident records. Clever offshore contract organizations have taken a proactive approach to establish their own comprehensive SEMS-like program before (or in case) it becomes specifically required of them by the BSEE. This approach will help ensure proper planning into future projects, costs, and contract resources.

Significance of subject matter
For those interested in the contractor SEMS impact, the primary learning objectives and outcomes of this paper include:Review contractor-specific SEMS elements and requirementsUnderstand four important SEMS contractor takeawaysOperators must conduct initial SEMS program audits by November 2013 and then every 3 years thereafter.Operators must conduct and document contractor selection processes, safety evaluations, and verify contractor personnel knowledge and skills in advance of performing work.BSEE will take SEMS enforcement action against contractors not meeting expectations.Within 30 days of the audit close, operators must send BSEE a detailed corrective action plan (CAP) that identifies each responsible person by name and job title.Review BSEE district investigation report data findingsGain knowledge of existing contractor management guidance, ideas, and resources

Description of the material
This paper provides operators with the necessary information to understand the minimum SEMS contractor expectations to ensure their contractors are a help and not a hindrance to their regulatory compliant and effective operator SEMS program and audit.
Buoyant Tower: Concept Selection - An Economic and Technical Evaluation
Authors: Spies Richard , Ortega Cesar , Ledgard Durkin 
Published: May 2013

Abstract
Based on a review of the BPZ CX-15 project, this paper outlines the business opportunities and challenges in delivering offshore oil and gas developments in Peru. Aging existing infrastructure and the need to create local capabilities combine with highly economic reserves of oil and gas to provide opportunities to enhance the Peruvian economy.
The development of new offshore fields in remote locations, such as Peru, where there are limited assets available to economically adopt conventional methods requires the use of innovative approaches to enable such projects to proceed. With design challenges driven by extreme seismic loading criteria, with local fabrication capabilities available but limited and with very limited locally available marine assets to perform drilling and construction operations there are considerable challenges to be overcome.
The paper details the economic and technical evaluation performed to demonstrate the benefits of the world's first application of buoyant tower technology. It also reviews the decision making process adopted in the evaluation of the different development solutions assessed including economic, schedule and other risk factors. This demonstrates that the adoption of such technology for offshore field developments in remote locations will enable more such developments to occur than would otherwise be the case using conventional solutions.

Introduction
About BPZ Energy. BPZ Energy, the operator that commissioned the CX-15 platform, is a small exploration and production company, with average production in 2012 of approximately 3,500 BOPD. BPZ Energy itself has limited resources but has a capable, if small, technical staff. Company operations have included over 100 oil field personnel and marine personnel to support operations in Block Z-1. Due to the limited marine support services available in this area, when operations ramped up to support first production, the company elected to form its own marine service operation, mainly by supplying and operating tank barges used as floating oil storage and conventional deck barges used as tender support for platform drilling operations or as crane barges with limited heavy lift capacity.
Financial resources of the company were tested by the CX-15 project, but the project was ultimately completed with bank financing as well as the sale of part of the Block Z-1, including the CX-15 project, to a 49% partner that entered the project when the CX-15 project was well underway.
Service Life and the Definition of Failure of Coatings and Cathodic Protection
Authors: Gibbs Brian , Graf Thomas 
Published: May 2013

Abstract
When corrosion protection systems fail to function correctly, all too often, the finger-of-blame is pointed at the technology used for corrosion protection as being the root cause. In reality, the failure is almost always in a management system that either is not correctly applied or is overlooked, and the physical breakdown is only the manifestation of the error. At the outset of a project, it is essential that clear expectations are established and agreed by all the stake holders. These expectations must consider both the capital project and operating phases of the intended facility, and a balance must be achieved between minimizing project time and cost and optimizing maintenance budgets and down time. Using risk analysis methods, these expectations should be transformed into performance standards and project specifications that are well understood by all involved parties, including those responsible for design, procurement, manufacture, construction, commissioning, operations, and maintenance. This presentation will highlight the important considerations and discussions that must take place before the corrosion protection system is designed. This must start with defining the expectations, which then leads into establishing the systems and controls that are needed to deliver the expectation. The focus of this presentation is creating the corrosion management systems that are need to be in place to achieve safe- and cost-effective service, and weighs the balance between CAPEX and OPEX constraints.
Buoyant Tower Design Innovation: Applying Deepwater Technology to Shallow Water Challeges
Authors: Hegler Russell , Finn Lyle 
Published: May 2013

Abstract
This paper presents a discussion of a new buoyant tower design for developing fields in mid-water depths (50 m to 250 m). A tower using this design was installed offshore Peru in the fall of 2012. This new buoyant tower design applied a number of deepwater technologies to shallow water. These technologies include the cellular construction of the hull, a suction pile like foundation, float-over deck installation, air over water ballast system, fixed ballast at the bottom, and unconditionally stable design approach.

Introduction
The buoyant tower concept is not a new idea for the oil business. A number of bottom founded structures held upright by buoyancy were installed in the North Sea years ago. The Brent flare tower and the Beryl articulated loading tower are two examples. All of these early buoyant towers used a mechanical pivot at the base. Some of them used a truss structure to connect the upper buoyancy modules to the base pivot. However, the offshore structure recently installed offshore Peru is the first buoyant tower to be used for drilling and producing operations.
The tower offshore Peru is also different from its predecessors in that the mechanical pivot was replaced with a suction can foundation (SCF). This foundation element performs the same functions as the mechanical pivot in that it allows the tower to rotate about the base in a compliant manner while restraining the base from moving vertically, laterally, and torsionally.
The idea of using a can in the soil to form a pivot also is not new. The test guyed tower installed in the Gulf of Mexico (GOM) in 1975 was supported at the base by a spud can. This spud can effectively formed a pivot in the soil allowing the tower to remain compliant to the wave forces. This tower experienced numerous winter storms during its four year stay offshore with no detectable vertical, lateral, or torsional movement.
Improving Durability of ROV Tether Cables by UHMWPE Fiber
Authors: Eijssen Marc , Gabrielsen Andreas 
Published: May 2013

Abstract
This paper describes the durability enhancement of Nexans' conventional ROV tether cable design by using a strength member made with a bending optimized Ultra-High Molecular Weight PolyEthylene (UHMWPE; also refered to as HMPE) fiber, manufactured by DSM Dyneema and branded as Dyneema®, and herewith creating opportunities for more costeffective ROV operations and more flexibility in the design of ROV tether cables. The improved ROV tether cable is manufactured by Nexans and branded as ENABLE®. As a physical connection between a Remote Operating Vehicle (ROV) and its tether management system (TMS), ROV tether cables are exposed to small bending diameters and relatively sharp directional changes in the TMS. During ROV operations the cables are exposed to axial loading, severe multiple bending in arbitrary planes and hydrostatic pressure. The internal friction caused by motions and hydrostatic pressure induces mechanical deterioration of the strength member in ROV tether cables, hence a loss of functionality and regular re-termination and cut-backs of the ROV tether cable. In conventional tether cable designs aramid fibers are commonly applied in contra-helically stranded layers around an electro-optical core. After a while in operation internal abrasion, misalignment and compressive failure of these fibers, especially at the section of the tether cable closest to the ROV, become apparent. Based on its physical characteristics, UHMWPE fiber holds promise to overcome these failure modes.
Summarizing the Deepwater Horizon/Macondo Reports
Authors: Sutton Ian S 
Published: May 2013

Summary
Whenever there is a serious incident, such as the Deepwater Horizon/Macondo explosion and oil spill it is normal for one or more authoritative bodies to write an in-depth report. Such reports are generally very thorough and are prepared by people of high credibility and professionalism within the industry or from related industries. Typically these reports describe:What happened: the sequence of actions and non-actions that led up to the event, followed by an assessment of the effectiveness of the emergency response systems.How the Safety Management Systems, both technical and managerial, failed to prevent the event from occurring and/or failed to mitigate the event once it was under way; andRecommendations to prevent further incidents of this type from occurring. These recommendations cover changes to regulations, developments in management systems and improvements in technology.
Finally, the reports may, on occasion, suggest a new paradigm for for managing safety in the industry covered. Examples of such paradigm shifts occurred in the 1990 (the Cullen report and Piper Alpha) and in 2007 (the Baker report and the Texas City explosion).
Of the many reports written to do with the Deepwater Horizon/Macondo (DWH) event of April 2010, four have been selected for review in this paper. In chronological order they are:National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling. Report to the President. January 2011.BOEMRE (Bureau of Ocean Energy Management, Regulation and Enforcement). Report Regarding the Cause of the April 20, 2010 Macondo Well Blowout. September 14, 2011.Transportation Research Board. Special Report 309: Evaluating the Effectiveness of Offshore Safety and Environmental Management Systems. 2012.SPE (Society of Petroleum Engineers). Summit Paper. The Human Factor, Process Safety and Culture. Eds. Patrick Hudson and John L. Thorogood. November 2012.
The third and fourth reports did not address the Deepwater Horizon event in detail. However both of them were profoundly influenced by the need to respond to this catastrophic event and provide guidance as to actions that can be taken to improve the culture of the offshore oil and gas industry.
Figure 1 shows a binder that contains a print-out of the four documents (along with copies of SEMS and the proposed SEMS II). They are printed single-sided on standard paper. The binder is 5 inches thick and weighs approximately 10 pounds, thus illustrating the scope of such reports, and the challenge that the offshore community faces in reading them and understanding their findings and recommendations.
In-Situ Requalification of Pressure Tubes: A New and Efficient Methodology
Authors: Harding Alan , Lawrence Lee , Irani Roy S. , Dickens Mark 
Published: May 2013

Abstract
This presentation focuses on a novel, newly published Standard, which will ensure off-shore companies operate safely and efficiently. British Standards Institute, has recently developed a unique standard BS 8562, allowing retesting ‘Pressure Receptacles’, without disassembly, from their operation. Vessels tested using this approach, often called ‘Jumbo Tubes’, are sometimes impossible to access fully after installation, on off-shore platforms, within semi-submersible drilling rigs/submarines hulls/buildings etc. Because of these adverse locations where the examination/ inspections are conducted, a critical part of the re-qualification requires the site's pre-testing assessment, to identify potential hazards, which need to be considered during the actual test programme. A 'Competent Person', whose qualifications are strictly defined and who must demonstrate know-how and judgement skills, at all times, undertakes the testing. The standard's title, " Gas cylinders. In situ, non-destructive examination and testing of refillable seamless steel tubes of water capacity between 150 and 3000 L, used for compressed gases??, speaks for itself.
Recently published, this standard has been successfully deployed in several harsh/inaccessible locations. An external visual inspection of all accessible surfaces is mandatory, whilst classical techniques such as corrosion mapping, magnetic particle/dye penetrant inspection, even hydraulic testing (where feasible and believed necessary) etc. may be performed. However, focus is on modern techniques:- ultrasonic examination (thickness surveys/flaw detection), eddy current testing, and possibly the most useful method of all, acoustic emission testing. Work has commenced to deploy this standard globally as EN/ISO standards. The use of non-destructive techniques has saved, on average, about 20% of the cost that would have been incurred, compared to conventional test methods, whilst also avoiding an immeasurable amount of operational disruption. For completed international Naval (submarine) applications the savings have amounted to over 60%!
4. A unique route of re-qualifying pressure receptacles, which otherwise would remain in a state of uncertain safety, has been developed. Actual savings apart, this approach is very 'green' too: none of the vessels are transported, whilst testing is during an actual filling operation. Additionally, the standard is invaluable to operations where the downtime involved would hinder either the installation's safe operation or its service.
Field Development Overview of Liuhua 11-1 and Liuhua 4-1 Oil Field
Authors: Zuan Yue , Yiyong Liu , Jianjun Yang , Jiayou Mao 
Published: May 2013

Abstract
The Liuhua 11–1 oil field, to date, the largest oil field in the South China Sea, is located in approximately 310 meter of water. It was the first deepwater field in the South China Sea originally developed by a consortium of Amoco, CNOOC and Kerr-McGee in 1995. The development includes a Floating Production System (FPS) with a subsea production system, and a Floating Production Storage Offloading (FPSO) located approximately 3km northwest of the FPS. The development of a nearby field, the Liuhua 4–1, about 11km away from Liuhua 11–1, was approved in early 2010 and produced in 2012 through the Liuhua 11–1 FPS facilities via subsea tieback, which requires to FPS life extension and topsides capacities upgrading for another 15 years. There are significant technical challenges for the life extension and dry dock upgrade of the FPS, as well as the subsea tie-back of the Liuhua 4–1 field. The FPS mooring and subsea control risers need to be disconnected and reconnected after the FPS drydock. The new 11km subsea pipeline between two oil fileds, control umbilical and electrical cable risers need to be installed. The FPS upgrade project started in 2010 and completed successfully in 2012 with the reconnection of the mooring and risers to the FPS. Both the Liuhua 11–1 and the Liuhua 4–1 fields are currently producing. This paper gives an overview of the Liuhua11–1 and Li uhua4–1 development as a case study for South China Sea deepwater development and also discusses the technology and project execution for developing nearby marginal fields.

Introduction
Liuhua 11–1 Oil Field is the deepest oil field on production in China to date, located in South China Sea, started first oil production on March 1996. She was called a " crown jewels" in offshore oil industry with a series of technical innovation at that time, and she is still on production after 17 years service. Liuhua 4-1, as a marginal oil field, was developed via tie back to the Liuhua 11–1 Oil Field, raised new requirement on the existing offshore facilities. China National Offshore Oil Corporation (CNOOC) faced serious challenges on facilities upgrade, FPS disconnection, re-hookup, and technicalogy and project management. The Semi-Submersible Platform FPS Nan " Hai Tiao Zhan" was disconnected on Oct. 2011, went to Dry Dock upgrading, re-hookup on location on May 2012. Liuhua 11–1 production resumed on June and Liuhua 4–1 started the First Oil on July and all 8 wells were on production in Sept. 2012.