bluuebunny/crossref_metadata_2025_split huggingface dataset:
Case Study on Polymer Gel to Control Water Coning for Horizontal Well in Offshore Oilfield
Authors: Dai Li Cai , You Qing , Yuhong Xie , Long He , Ya Cui , Fulin Zhao 
Published: May 2011

Abstract
This paper describes polymer gel with different gelation time for water coning control in horizontal well located in Weizhou 11-4 offshore oilfield, CNOOC, China. The selected horizontal well was shut in with zero oil production and 100% water cut before treatment. This paper also reports the detailed information about the treatment, including production history of this horizontal well, gelants formulas with different gelation time optimization, operational procedure and reservoir performance after treatment. In addition, a method is built up to control water coning for horizontal well in offshore oilfeild. The gelants formulas are 0.30%HPAM +0.60%phenol formaldehyde resin, 0.40%HPAM+0.10%Na2Cr2O7+0.20%(NH2)2CS and 0.40%HPAM+0.20%Na2Cr2O7+0.40%(NH2)2CS, with corresponding gelation time of 3.5 day, 2.0 day and 1.0 day separately at 75 degrees celsius. The above gelants were successively injected with injection volumes of 384 m3, 256 m3 and 128 m3. The overdisplacing fluid was used to displace gelants away from percolation area. Then the well was shut in for 4 days in order to form gel that could be used as packer between oil-water interface to control water coning. At the same time, real-time monitoring data about injection pressure and rate were also recorded. The treatment resulted in an oil increase of 16.3~27.4 t/d and average water cut decrease of 6%~9% in one year after treatment.

Introduction
Excess water production from oil well has become a serious problem for oil & gas field due to long term of water flooding. High level of water production leads to increase corrosion and scale, increase load of fluid-handling facilities, increase environmental protection concerns and eventually shut-in well, especially in offshore oilfield. Consequently, producing zone is often given up in an attempt to avoid excess water produce, even when the intervals still have large volumes of remaining hydrocarbons. Therefore, controlling water production has become more and more important to oil industry in the world.
It is widely reported that polymer gel treatment is a cost-effective method to improve sweep efficiency in reservoirs and to reduce excess water production during oil & gas production. The gelant formed by polymer and cross-linker is injected into target formation which is high water cut zone and react to form gel to fully or partially seal the formation at reservoir temperature(Sydansk, 1992 and Fulin, 2001, 2006).
Integrity Management: From Design to Decommissioning Through IMMR for Floating Units
Authors: Franco Mireille , Cholley Jean Marc 
Published: May 2011

Abstract
Creating and maintaining asset integrity is a complex aggregation of many different activities that all together will provide the required assurance.
Part of the cycle is the IMMR: Inspection Maintenance Monitoring and Repair.
Integrity verification/assurance activities are in place throughout production, maintenance and inspection.
Verification tasks are principally managed through adequate software which is the master repository for technical data and daily activity management.
An essential step of integrity management is to regularly verify the validity of the corrosion prevention, inspection and maintenance programs, ensuring they cover all the identified risks, and that they comply with the control points defined in the performance standards.
Implementing IM aims at ensuring the solidity of the assurance processes used for checking that requirements are met, results recorded and assessed. Ultimately, this is achieved when monitoring results comply with Performance Standards. Most important aspects should be measured and reported through performance measures & KPIs.
For some strategic assets or where specialized skills are required the verification of compliance normally performed by the affiliate can be complemented/ validated by a Surveillance Team composed of specialists from the Head Office.
This is currently the case for pipelines, flexible lines and Floating Units.

Application
The constitution, role and responsibilities of Surveillance Teams are formalized as part of corresponding management systems.
The overall Technical Integrity Assurance Process includes the verification and measure of compliance with Performance Standards, which are essential to demonstrate that the preventive and mitigation barriers are in the expected state of condition and fulfill all required functions. This is the place for IMMR plan

Observation and Conclusions
When in a floating unit, Class and the application of International Maritime Conventions play a role inside the IMMR plan and the strategy defined.
Hull integrity problems do occur and most of the decisions to be taken are required on site with minimal impact to production.
The relative short life of operating floating units has as a consequence a relative short historical data about hull integrity, hull performance and repair procedures on site.
Emergency Pipeline Repair Equipment - Site Integration Tests and Post SIT Engineering
Authors: Rebello Armando , Ayers Ray R. , Long Randy 
Published: May 2011

Abstract
Since the onset of Deep Water Response to Underwater Pipeline Emergencies (DW RUPE) JIP in 2005, we have been reporting on progress of the development of a repair system designed to repair ANSI 1500 class pipelines in the 10-inch to 24-inch range in water depths up to 10,000 ft. For each pipe size, the system provides a minor repair kit with one structural clamp, and a spool assembly kit with two connectors. 6,5,4,3,2,1
Following delivery of the repair system, composed of pipe lifting frames (PLFs), indexing base frames (IBFs), weld seam removal and FBE removal tool, cutting and end preparation tools, connectors and clamps, the system was subjected to System Integration Trials (SIT) in November 2009.
This paper reports on the SIT, post SIT conclusions and the path forward since the SIT, with regards to design modifications, storage techniques, assembly of the equipment, mobilization and management of the system.

Introduction
The word that comes to mind in response to damage to pipeline infrastructure is " immediate??. The speed of reaction to a given subsea pipeline repair problem will dictate the financial impact, including production loss, potential liability and reputational damage for pollution issues, in addition to the cost of the repair itself. Consider the time it will take to order simple forgings needed for the manufacturing of repair clamps and connectors, currently in the order of 8 to 10 weeks, let alone the time to machine and assemble all components, and the cost of preparedness will be fully justified.
However, given the fact that the likelihood of such emergency is relatively small, many oil and gas companies still do not have any dedicated effort established toward maintaining repair tools and consumables on the shelf.
DW RUPE is a non profit co-ownership project dedicated to such emergencies, where the cost of equipment and tools is proportionally shared among its co-owners.
After completion of the asset acquisition phase in 2009, DW RUPE had a set of components needed to conduct repairs on pipelines in deep water. It was important to test the tools and equipment assembled as a system, in order to identify any problems before a real repair had to be conducted. A significant factor for the SIT was the fact that at the end of 2009, the IBFs and PLFs supplier encountered completion issues and DW RUPE took responsibility for operational readiness and any required improvements.
The lessons learned from the SIT were converted to a list of improvement tasks that are being implemented in their order of priority, for completion before 2011 hurricane season.
The 2nd Generation DC All-Electric Subsea Production Control System
Authors: Abicht Daniel , Van Den Akker Jan 
Published: May 2011

Abstract
With the successful operation of the first All-Electric Production Control System this technology continues to proven its advantages. With a system availability of well above 99.9 % (status Dec, 2010), initial development targets have been significantly exceeded. While this pilot system further continues to gain field experience, the development of the 2nd generation DC All-Electric Subsea Production Control System already is in its final stages.
A mature development initiative planting the design on the successful and field proven CameronDC™ System has been initiated. Key target was a further simplification of the system architecture and an implementation of a state of the art fiber optics communication while maintaining commercial feasibility. As a result the advantages of the DC All-Electric technology such as environmental friendliness, improved reliability & availability and real time feedback are combined with the advantage of a high speed communication using fiber optic in one Production Control System concept. Naturally, relevant standards including API 17N have been considered as part of this development initiative.
The 2nd generation DC All-Electric Subsea Production Control System represents state of the art technology in several aspects. High voltage transmission enables significant step-out distances. The available high bandwidth enables a transfer of large data amounts even for complex field architectures. Functionalities to control subsea actuators have been expanded. The already applied performance assessment approach enabling incipient failure detection has been maintained.
Discussing the operational feedback as well the development targets this paper will introduce the concept of the 2nd generation DC All-Electric Subsea Production Control System and address its inherent advantages. The qualification strategy will be outlined. It also will describe the experience gained during the development.
Blade Inspection Guidance for Offshore Wind Turbine Facilities
Authors: Sheppard Robert Edward , Puskar Frank , Waldhart Chris 
Published: May 2011

Abstract
Blades form an integral part to the operations and structural response of wind turbine facilities and demonstrating their long-term integrity in an offshore environment is challenging. Known blade degradation mechanisms and those that are likely in specific US offshore areas are considered along with evaluations of various inspection and condition monitoring capabilities, both now and in the near future. This paper is based on a study funded by the US Department of the Interior, Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE).

Development Approach
The inspection guidance development started with understanding existing blade inspection practices for both land-based and offshore facilities through a literature search and discussions with industry experts from the manufacturing, service and operational sectors, and others with broad industry experience. Also considered were inspection technologies and practices expected to be available for practical implementation within the next few years since these will likely be in use when the first US offshore wind turbine facilities begin operating.
In order to evaluate the pros and cons of various inspection practices, both established and novel, and determine the best approaches to recommend, a set of criteria were established to compare the various practices against each other:Worker Safety - the ability to implement the inspection safely and effectively considering the access requirements for blades in an offshore environmentScalability - the ability to implement the inspection across multiple facilities in a fieldRepeatability - the ability to reliably reproduce the inspection activity and obtain results that are consistent on the same blade and across multiple blades in a fieldCost effectiveness - qualitative assessment of the inspection cost in terms of manpower, downtime, and duration weighed against the potential data gathered
Subject matter experts were queried regarding prevalent blade damage mechanisms, techniques used for identifying damage and in what situations each would be implemented, what access equipment and systems are used, and what technologies are available, or will be available, that have the potential for widespread use within the next five to ten years.

Damage Mechanisms
Current practice for blade inspections for land-based and offshore facilities is generally driven by knowledge of defects in similar blades or problems identified in the power performance of a particular turbine. In developing guidance for more proactive inspection and monitoring programs, it is useful to understand what mechanisms affect blade performance.
Qualification Testing Of Flexible Pipes For 3000m Water Depth
Authors: Bectarte Fabrice , Secher Philippe , Felix-Henry Antoine 
Published: May 2011

Abstract
The paper is relevant to riser technology and specifically, qualification of flexible pipes for water depths up to 3,000m.
This paper describes a comprehensive program aimed at the qualification of flexible pipes for ultradeep water applications. The primary design driver for ultradeep water flexible pipe applications is the resistance to hydrostatic pressure, in combination with dynamic curvature cycling. The two associated critical failure modes are hydrostatic collapse and lateral buckling of armour wires.
Technip have developed dedicated flexible pipe components to address the severe loading conditions encountered in water depths up to 3,000m. Hydrostatic collapse resistance has been addressed by a thick inner carcass layer and a PSI pressure vault. Armour wire lateral buckling, which is induced by axial compression in the armour wires in combination with dynamic curvature cycling, has been addressed by the design and industrialization of new tensile armour wires.
The design qualification process for these improvements was completed on two levels. Initially, a large number of pipes were subjected to dynamic cycling testing under high hydrostatic pressure in a hyperbaric chamber so as to determine design limits in terms of pipe diameter, water depth and component sizing. Then, design combinations were selected for testing in a real deepwater environment in the Gulf of Mexico. This second level of tests referred as Deep Immersion Performance (DIP) tests aimed at validating the results obtained from hyperbaric chamber tests. The DIP tests replicated the actual design conditions to which a flexible pipe would be subjected during installation and operation.
The development of new and modified flexible pipe components provided a suite of flexible pipe designs suitable for extended water depth application. The final phase of the qualification program, namely the DIP tests, was completed in 2010. It provided design limitations of the new designs for both 9?? and 11?? internal diameter flexible pipes, in sweet and sour service in water depths up to 3,000m
This paper clearly demonstrates the suitability of flexible pipes as a valid solution for ultradeep water applications as long as the mechanical behavior of the pipe components is adequately addressed.

1. Introduction and objectives
The objective of this paper is to describe the comprehensive R&D project for the qualification of flexible pipes in water depths up to 3000m.
The main and primary purpose of this R&D program was to demonstrate that the validation range of our flexible pipes can be extended from depths of 2000 m (as it was before project) to beyond today's market needs in Brazil and the Gulf of Mexico (Figure 1), i.e.3000 m for flexible pipe risers between 7?? and 9??2400 m for 11?? flexible pipe risers.
A secondary objective was to extend to 3000 m, the validity range of our design models and of our testing methodology.
Generation of Best Practices in Flow Assurance Using a Transient Hydrate Kinetics Model
Authors: Zerpa Luis Eduardo , Sloan E. Dendy , Sum Amadeu , Koh Carolyn 
Published: May 2011

Abstract
The paper highlights the importance of developing a comprehensive gas hydrate model in flow assurance for the oil and gas industry. The comprehensive model should account for mechanisms present in different systems of oil/gas production. Since this kind of tool could be seen as complex and difficult to use, the main focus of the paper is to present an example of generation of "best practices" that can address the needs of a general flow assurance community, using a gas hydrate model developed for oil-dominated systems. The example illustrates the restart of an offshore well, using a typical geometry and fluid properties from the Caratinga Field located at Campos Basin, Brazil. Two extreme cases are studied to identify the worse case scenario, one considering a water-in-oil stable emulsion and the other where water is allowed to separate from the continuous oil phase. Then, the restart procedure of the case with higher risk of forming a hydrate plug is optimized to minimize hydrate formation and plugging risk. From the comparison of the two cases studied, it is concluded that systems with free water have a higher risk of plugging with hydrates. The optimization of the restart of a well shows that a slow restart of the well minimizes the formation of hydrates, decreasing the risk of plugging. The main conclusion is that the gas hydrate model can be used as a tool for the generation of "best practices" for gas hydrates in flow assurance.

Introduction
Flow assurance is a technical discipline of the oil and gas industry that focuses on the design of safe and secure operation techniques for the uninterrupted transport of reservoir fluids from the reservoir to the point of sale. Offshore explorations in deeper and colder waters impose more challenging scenarios to the flow assurance of the produced streams, requiring production facilities with longer subsea tiebacks for the transport of hydrocarbons from the wellhead to production/processing platforms. These facilities may operate at high pressures and low temperatures promoting the formation of gas hydrates, crystalline compounds formed by hydrogen-bonded water molecules in a lattice structure that is stabilized by encapsulating a small guest molecule, like methane or ethane (Sloan and Koh, 2008). One of the most challenging problems in flow assurance is the plugging of pipelines due to rapid formation of gas hydrates compared to other solid deposits (Sloan, 2005).
The formation of gas hydrates in an oil-dominated multiphase flow system containing water, oil, and gas, can be described using the conceptual model illustrated in Figure 1, where hydrates form at the interface of water droplets entrained in the continuous oil phase. In the oil phase, these hydrate-encrusted water droplets can agglomerate increasing into larger hydrate masses, leading to an increase in the slurry viscosity, which can eventually form a plug (Turner, 2005).
Deepwater Seafloor Resource Production - The Bismarck Sea Development Project
Authors: Smith Glen 
Published: May 2011

Abstract
Nautilus Minerals, the world's leader in exploration and development of deep ocean seafloor resources, has located a number of high grade copper and gold Seafloor Massive Sulphide (SMS) deposits in the Bismarck Sea, Papua New Guinea (PNG). Nautilus' business model is based on the notion of ongoing resource accumulation and " aggregation?? of numerous high grade SMS systems to sequentially develop using an offshore production system. Nautilus' record of discovery of new SMS systems in clusters in the Bismarck Sea and in Tonga is in keeping with " camps?? of land based Volcanic Hosted Massive Sulphide (VHMS) systems that form a significant part of the world's reserves of copper, lead and zinc.
Nautilus' development plan is to commence production at its Solwara 1 site located within Mining Lease (ML) 154. As of January 2011, the indicated and inferred mineral resources attributed to the Solwara 1 deposit are 870 kT and 1,300 kT respectively. Nautilus is continuing an exploration and resource evaluation program with the expectation that Solwara 1 and other prospects in its Bismarck Sea tenement holdings will translate into an increased aggregated commercially viable reserve.
This paper summarises a progress update of Nautilus' development plans which will provide a new source of minerals for the world and create a clear benchmark in environmental and community standards for this emerging frontier.

Introduction
Nautilus is focused on its exploration and development plans for the recovery of high grade copper and gold in SMS mineralisation. These mineralised belts, analogous to land based VHMS deposits, are typically located in areas associated with submarine volcanic activity along deepwater mid-ocean ridges or back-arc basins.
Nautilus' exploration programmes have predominantly focused on the Bismarck Sea, a benign body of water within the territorial waters of Papua New Guinea. Nautilus has used or adapted existing technologies to achieve a very high success rate in generating and converting targets into high grade SMS mineralised discoveries.
Nautilus' first development project is located at an approximate water depth of 1,600 m at its Solwara 1 site. Its plans have focused on the use of existing technology and market leaders in the development of an offshore production system that can be relocated and re-used on subsequent sites.
Frigg Decommissioning: Onshore Disposal
Authors: Oram Michael Ellis 
Published: May 2011

Abstract
This paper describes the work methodology for the handling of all offshore inventory landed at the onshore disposal sites. Specific items which are addressed include:Introduction including Company role, total tonnage & relevant Authorities.Deconstruction & Disposal worksites including location and capacity.Onshore disposal process including preparations for receipt of inventory, safety inspection, removal of hazardous waste & removal of items for re-use or sale.Demolition methods including mechanical cutting (cold) & hot cutting.Classification of inventory for disposal.Handling & disposal of hazardous waste.Jacket dismantling including two alternative methods.Safety Management Systems employed.Onshore man-hours.Jacket tdismantling.Lessons learnt.