bluuebunny/crossref_metadata_2025_split huggingface dataset:
Key learnings: Risk based verification of process systems on a floating LNG producing unit
Authors: Skramstad Erik , Almandoz David Anthony , Savio Fredik 
Published: July 2010

Abstract
LNG production facilities installed on a floating unit are currently being developed by several companies. Such facilities involve process applications similar to those that are commonly in use in the industry but have not been previously deployed on a floating unit in a marine environment.
FLEX LNG commissioned DNV and CH-IV International to review their process solution with the aim to verify the performance of the process.
A novel and risk based approach was adopted to ensure an efficient and focussed review in which the systematic application of DNV's Technology Qualification procedure was adopted as a means to screen the solutions and identify areas of particular concern.
The identified areas were subjected to detailed and expert technical assessment and on this basis a total assessment of the system solution was made.
The technical assessment included the review of use of columns and heat exchangers in liquid and gas operations and novel application of mechanical components and rotating equipment.
It was demonstrated that the majority of the effects of the vessel motions and the marine environment had been identified and addressed in the design of the plant and that no major issue that could not be addressed (showstoppers) was identified. Further, it was concluded that the selected approach provided an effective and focussed assessment of the process solution.
This paper will present–Background for the verification–The selected approach–Discussion of some of the identified issues and their impact–Key conclusions and recommendations

Introduction
LNG production facilities on floating facilities (FLNG or LNG FPSOs) are being considered and developed by several companies with the aim to monetise stranded gas fields. The results from these studies indicate that these solutions are technically feasible and also that the benefits from fabrication in industrialised facilities as opposed to field-erected facilities make these solutions attractive in an investment perspective compared to many land based facilities.
The experience base from LNG liquefaction processes on floating facilities is limited to experience gained from reliquefaction plants on LNG carriers and from similar process applications on LPG FPSOs. The experience base for typical oil FPSOs is significant, but not fully applicable due to the complexity of the processes involved in LNG production when compared to process designs commonly employed for FPSOs.
A key uncertainty in the assessment of the commercial feasibility of a FLNG field development will be the performance and capacity of the production chain which will involve novel solutions both with regard to production facilities, offloading and the transport solutions.
Parque das Conchas (BC-10) Steel Lazy Wave Riser Installation: Pre-Abandonment, Recovery and Transfer Challenges
Authors: Thomas Biju , Benirschke Anton , Sarkar Tanmay 
Published: July 2010

Abstract
The Parque das Conchas (BC-10) project is located in deepwater, in block BC-10, off the coast of Brazil. It comprises a number of subsea fields tied back to a centrally located turret moored Floating Production Storage and Offloading (FPSO) host in some 1800 meters of water. This paper describes the installation engineering challenges for the 7 Steel Lazy Wave Risers (SLWR) and the dynamic sections of the 3 umbilicals that are part of the Phase 1 scope of the project.
To decouple the schedule risk of the installation of the subsea systems from the FPSO arrival schedule, a pre-abandonment, recovery and transfer method of the SLWR and umbilical in lazy wave configuration was chosen. Successful installation of SLWR by this method to the FPSO turret required the design of a suitable pre-abandonment layout taking into consideration the installation sequence and careful assessment of the risks involved particularly in terms of clearance and interference issues with FPSO mooring lines and the already transferred SLWRs/ umbilicals.
Pre-abandonment, recovery and transfer by keel haul of this " worlds first?? SLWR system had a number of challenges that had to be overcome. These include determining the pre-abandonment route of SLWR, lay tension to balance curve stability, lazy wave ‘hump’ stability while on seabed, lay stresses on flex joint, etc.
The recovery and transfer operations had challenges associated with clearance monitoring with mooring lines and already installed risers as well as maintaining the design touch down points.
The pre-abandonment layout was developed using Shell's in-house design tool for high level assessment followed by detailed engineering installation analysis by Subsea7 using Orcaflex. This enabled the development of analytical procedures to assess and mitigate the risks involved in pre-abandonment, recovery and transfer operation of SLWR. Subsea7's construction vessel ‘Seven Oceans’ performed the SLWR and dynamic umbilical installation activities.
This paper describes how this complex riser operation was modeled and successfully executed.

Introduction
The Parque das Conchas (BC-10) project is located off the coast of Brazil in the Campos Basin in water depths from 1190 meters to 1940 meters. Shell is the operator with a 50% working interest in a Joint Venture with Petrobras (45%) and ONGC (15%). During Phase I of the project, the Ostra, Abalone and Argonauta B-West fields were tied-back via SLWR's to the turret-moored FPSO in approximately 1800m water depth as presented in Figure 1. Argonauta O-North is planned to be developed as part of Phase II of the project.
SS: Atlantic Canada
Authors: Paulin Mike , Thistle Stephen , Kennedy Kurt 
Published: July 2010

Abstract
A study was completed in early 2008 (IMVPA, 2008) for the US Minerals Management Service (MMS) with the objective to deliver an assessment of oil and gas technology that may be applied to cold regions of the United States Outer Continental Shelf (OCS). An overview of this study and its results are presented in this paper.
This study assessed the current state of offshore technology in arctic and sub-arctic regions. The results of this assessment were used to provide insight and guidance into existing/future exploration and development technologies that might be applied on the US OCS, in particular those areas in the Beaufort, Chukchi and Bering Seas.
The work covers exploration structures, bottom-founded and fixed production concepts, floating production concepts, terminals, pipelines and subsea facilities, and also touches on other technologies that might be relevant to Alaskan OCS exploration and development. Advances in harsh environment offshore exploration and production technology have made it economically and technically feasible for some projects to proceed in ice-covered waters, and additional projects may be possible in future.
This study drew on a review of current state-of-practice and state-of-the-art used in, or proposed for, arctic and sub-arctic offshore development areas. Assessments of exploration and production options were primarily based on technical feasibility. As appropriate, other aspects were also considered including constructability, capital costs, environmental considerations, operations, maintenance and repair, abandonment and decommissioning.

Introduction
Offshore hydrocarbon exploration and production requires a bottom-founded platform, an artificial island, or a floating structure plus subsea equipment including pipeline/riser systems. Transportation of produced hydrocarbons to market is also an essential aspect of any development. An added complexity when hydrocarbon resources are located in arctic regions is the presence of first-year and/or multi-year ice during a significant part of the year. Global climate changes may also result in longer open water seasons in the future, which may lead to more significant storm events that must be considered in the design of full-field offshore development concepts for arctic regions.
A number of " cold regions?? offshore developments have been carried out or are planned worldwide, including the east coast of Canada (Hibernia, Terra Nova, White Rose), Sakhalin Island (Russia), Kashagan (Caspian), Shtokman (Barents Sea) as well as in the Beaufort Sea (Northstar, PanArctic Drake). An understanding of these analogue projects, as well as those already operational or planned for the United States (e.g., Northstar and Oooguruk), can provide insight and guidance into potential exploration and development technologies that might be applied to cold regions of the United States Outer Continental Shelf (OCS).
Offshore Petroleum Play Fairway Analysis and Geoscience Data Package Program
Authors: Van Belle Olivier Stephan Eduard , Wilson Hamish , Luheshi Matt , MacMullin Roderick Alexander , St-Amour Wayne 
Published: July 2010

Abstract
The Nova Scotia Department of Energy and Canada-Nova Scotia Offshore Petroleum Board have carried out a sound technical work program over many years to present potential licensees with the information to encourage them to invest in Nova Scotia. However, following some success, the result in terms of licence bids in Nova Scotia's offshore, wells drilled and hydrocarbons won, has proved disappointing. The value of the hydrocarbon province has not been fully unlocked. Although production and proven discoveries demonstrate that there is a working hydrocarbon system oil companies are leaving Nova Scotia in favour of other opportunities prior to completion of their exploration program. There is a view that, in order to attract new investors, it will be necessary to lower the barriers to entry. One of these is undoubtedly the ability of new investors to easily and quickly develop a good geological understanding of the Nova Scotia offshore basins and thus investment decisions. The intent is to conduct an industry-standard sequence stratigraphic based Play Fairway Analysis to a level of detail that is sufficient to give credibility to the outcome. It is also intended to conduct special studies that can help address the key exploration risks. Furthermore, this paper elaborates on the importance of the Geoscience Data Package for this program, and its effectiveness in re-invigorating interest in the Scotian Margin. Data availability, to support the comprehensive geotechnical evaluation, is key to reducing the barriers to entry into the region, but unfortunately it is not easily accessible to investors. The lack of a publicly available and industry-credible, geological framework, in conjunction with the fact that most geoscience data, specifically seismic data, is not freely available in full digital format is a major hurdle. The Offshore Petroleum Play Fairway Analysis and Geoscience Data Package program, for which the business rational is discussed in this paper, are aimed at addressing this issue.
SS: Perdido Development Project: Spar & Moorings
Authors: Lohr Curtis , Smith Keith 
Published: July 2010

Abstract
A Spar was selected for the Perdido Development during system selection in 2005 to provide a stable platform for direct vertical access drilling and producing operations for the world's deepest drilling and production platform in nearly 8000 feet of water. A combination polyester / chain mooring system was selected to place less vertical load on the floating structure (compared to a steel mooring system), which results in less payload on the structure and a lower overall cost solution for the project's host platform.
The transportation and installation of the Perdido Spar and moorings was completed during 2008. A number of records were set during the installation campaign including the world's deepest Spar installed in 7817 feet of water and the world's deepest permanent mooring pile in 8631 feet of water.
Challenges of interest to the offshore industry that contributed to the uniqueness of the Perdido Spar and moorings were:Impacts of Topsides single lift on the Spar design and weight managementSafety management given a project goal of zero recordable injuriesUltra deep water location with increased environmental requirements and significant seafloor hazardsPolyester permanent mooring systemSpar fixed ballast installation accuracySpar installation during hurricane season
This paper will provide a broad overview of various aspects of the Perdido Development Spar and mooring system design, fabrication, transportation and installation while highlighting the main challenges encountered and lessons learned for future projects.

Introduction
The Perdido Spar is Shell's first Spar Host production platform, but has the benefits of being developed as a joint venture with Chevron and BP. Technip was selected as the Spar and Mooring contractor in April 2006 and began detailed design on their 14th Spar in June 2006. An EPC contract was awarded to Technip USA in November 2006 for design, fabrication and dry transport of the Spar and Mooring work scope on the Perdido Development project. The Spar & Mooring Leads for Shell were primarily co-located with the Technip project management team at Technip's Woodbranch II PM&E office and in Shell's Woodcreek office in Houston. The Spar Fabrication Site Team was located at Technip Offshore Finland's yard in Mantyluoto, Finland.
Working relationships with Technip were excellent and were developed early in the project through focused team building sessions in Finland and Houston. An alignment workshop primarily aimed at " incident and injury free?? safety management and working relationships was held in October 2006 and attended by the most senior management from both Shell and Technip.
Heerema Marine Contractors (HMC) was selected in early 2006 as the transportation and installation contractor (excluding the dry tow from Finland). The Heerema project team was based in Leiden, The Netherlands while the Shell T&I team was based in Shell's Woodcreek office in Houston.
Integrated Operations and Integrity Management: Subsea System Vendors as Value Added Providers
Authors: Knight Kevin R. , Akinkunmi Olutayo , Koppervik Ingvar 
Published: July 2010

Abstract
The recent resurgence of interest in Integrated Operations (IO) and Integrity Management (IM) for the oil and gas industry has triggered necessary discussions of why revisiting these ideas and initiatives is important to the future of the industry. By implementing IO and IM programs and initiatives, operators gain an advantage in achieving increased recovery, reduction of operating expenses (OPEX), efficiency in execution, and optimization of asset availability. More than ever, the operator is held accountable by company stakeholders to determine rationalization when implementing any new program. This paper is to provide supportive rationale that the operator needs in choosing the subsea system provider as the best equipped to develop the intelligence engine driving its IO and IM programs.
The key to a successful IO and IM program design and implementation lies in the provider's proven history of experience and competence in the areas of well completion, production flow management, power distribution (hydraulic and electrical), controls (subsea and topside), installation, intervention, and life of field services and support. On both the technical and logistical sides of IO, expertise in these areas lends to the provider a better comprehension and applicable tools essential to the successful and effective implementation of a real-time diagnostics system and the associated support services program, including:Risk identificationRisk mitigationPerformance attributes and trends (system and component)Preventative maintenance program enhancementFailure modes (system and component)Performance indicator algorithm developmentSystem integrationEvent response support and counselTimely intervention planningImproved intervention execution
After being presented with this information, the IM program management of the operating company will understand why their program's success is greatly increased when it is backed by a reliable partnership with a subsea system supplier. Additionally, the operator will possess a clear set of criteria to help them evaluate potential suppliers of this valuable support piece ensuring them continuous and reliable production operations over the life of the field.
Controlling Export Pipeline Pressure To Optimize Gas Throughput From The Mirage Floating Production Unit
Authors: Frazer George Ross , Reed David , Hines John 
Published: July 2010

Abstract
Deep-water production in the Gulf of Mexico and other basins normally relies on tying into existing shallow water transmission lines. Efficient production of the reserves from deep-water fields many times requires the incoming lines be operated at a pressure above that for which the downstream segment was designed or that the applicable codes will allow.
ATP Oil & Gas Corporation's (" ATP??) Gulf of Mexico Mirage Field in 4000' of water was no exception to this problem. The results of field-production modeling to optimize reserve recovery clearly demonstrated the field's gas export line required operation at a pressure significantly above that of its shallow water transmission line destination. At an early stage in the project, ATP sought the guidance of both the transmission line operator and the Minerals Management Service. Numerous flowing and shut-in conditions were modeled to insure the resultant protection systems were capable of responding to the full range of expected daily operations. It is expected that the methods and systems thus developed will serve as a template for future deep-water export pipeline system planning and operation.

Introduction
The Mirage Field is the anchor of the first phase of the development of the Telemark Hub (" Hub??) in the Gulf of Mexico. Mirage (MC 941), Morgus (MC 942) and Telemark (AT 63) together constitute ATP's leases in the area. All of these had been discovered and evaluated by other operators and, for various reasons, been judged below their thresholds for development. ATP acquired all three via farmout or purchase.
Along with the gas-export pipeline overpressure protection system, the development solution for the Telemark Hub includes the use of several novel approaches for the Gulf of Mexico. The export pipeline's origin is a first-of-its kind floating production system (" FPS??) that is described in another paper at this conference. The top-tension riser system, mooring installation method, well drilling/completion modes and well-control hardware are also either innovative or on the forefront of deep-water field development applications.
The oil export system is a 10?? O.D. line that runs almost due northwest from the platform before turning north and tying into the Mars oil export system in MC Block 718. Its total length is approximately 22 miles. The 10?? gas export system (and topic of this paper) runs parallel to the oil export system but continues northwest until it ties in to the Discovery (" Discovery??) gas export system roughly 63 miles away in GI 115. Both lines originate from the FPS as steel catenary risers. Figure one is a high-level sketch of the general arrangement of the platform and its export system.
Blind Faith Gas Export Pipeline Pre-commissioning and Commissioning (PCC) Challenges
Authors: Shen Harry Y. , Phan Huy Thanh 
Published: July 2010

Abstract
This paper concentrates on the challenges, experience and lessons learned during the Precommissioning and Commissioning (PCC) of the Blind Faith 14?? to 18?? gas export pipeline.
The PCC for the Blind Faith gas pipeline took place in 2008 and was an extremely challenging phase of the project. The challenges were associated with the complexity of the subsea architecture at the interconnection of the new Blind Faith gas pipeline and the existing Canyon Chief gas pipeline (Refer to OTC paper 19764 for the tie-in between Blind Faith and Canyon Chief systems). The complexity was further challenged by the need to minimize the amount of shut in days for the production of the Canyon Chief gas pipeline. The PCC occurred in two phases:
Phase I - Without shutting in existing production on Canyon Chief gas pipeline:Hydrotest the Blind Faith gas pipelineDewater and inhibit the Blind Faith gas pipeline subsea by a pig train consisting of 4 pigs and three slugs of MeOH
Phase II - Shutting in existing production on Canyon Chief gas pipeline:Blowdown the Canyon Chief gas pipeline (during blowdown, recover the gas rather than venting to atmosphere)Dewater and inhibit an isolated two miles section in the Canyon Chief gas pipeline by the pig train from Blind FaithRetrieve pigs and recover methanol at MP-261ARestart Canyon Chief pipeline and provide buyback gas to Blind Faith
The PCC architecture and commissioning challenges included the following:Deepwater GoM - up to 6800' fswMultiple pipeline diametersLong pipeline distanceLimited nitrogen flow rateDewatering through a gas pipelineDrying of gas pipelineLimiting number of shutdown days for existing production
The PCC effort took approximately three months to complete, during which time the project experienced two back to back hurricanes and Phase I was performed twice due to pig related issues.
A New Tank Containment System to Floating LNG and CNG Processing and Storage Offshore Platforms
Authors: Lamb Thomas , Ramoo Regu , Parthasarathy Mohan , Santini Julien 
Published: July 2010

Abstract
Current interest in floating LNG systems is focused on the Floating Oil/LNG Processing and Storage Offshore Platforms (FOLNGPSO) and Floating LNG Processing and Storage Offshore Platforms (FNGPSO). A number have been built and many more are in design. In the last few years interest in Floating CNG Platforms has developed and a number of designs completed. A new tank containment system which has shown significant operation and acquisition cost benefits for LNG and CNG carriers is even more beneficial to the FLNGPSOs and FNGPSOs especially its ability to withstand sloshing loads in partially filled LNG tanks. Extensive structural analysis has been performed for both the LNG and CNG cases and the results, which validate the tank containment approach, are presented.

1.0 Introduction
In the past few years interest in Floating Oil/LNG Processing and Storage Offshore Platforms (FOLNGPSO) Floating LNG Processing and Storage Offshore Platforms (FNGPSO) has increased and a number have been built or are under construction and many more are in design. More recently interest in Floating CNG Platforms has developed and a number of designs completed. The collection and transport of natural gas from small (stranded) gas fields has been investigated for the past 15 years. It has been concluded that the best way to collect and transport gas from a small field is by compressing it. Compressed natural gas (CNG) requires a storage volume approximately twice that of LNG but does not need the expensive refrigeration plant at the source or the gasifying equipment at the receiving end. This can be clearly seen from the results of a study (CMCNG 2006) shown in Table 1.
Even though the capacity of natural gas is small, a CNG platform would still be relatively large in length. The problem is that the weight of the gas storage tanks is great, about 50,000 t for a cargo deadweight of only 15,000 t. This results in a very low deadweight ratio.
A solution that has superior volumetric and weight usage for both LNG and CNG is proposed that utilizes a new containment tank system that can be applied to both LNG and CNG, namely the Cubic Doughnut Tank System (CDTS). Previous papers (LAMB 2009OTC, RAMOO 2009, LAMB 2009) have described the development of the CDTS and its applications to both LNG and CNG Carriers with a brief mention of its application to floating production and storage platforms for both LNG and CNG. The first two of these papers also presented detailed structural analysis for LNG and the last one for CNG applications and these will not be repeated in this paper. However, updates to the analysis will be presented. This paper will present a brief description of the CDTS and, in more detail, its application to floating platforms for LNG and CNG offshore production and storage platforms.