bluuebunny/crossref_metadata_2025_split huggingface dataset:
Geological, Geophysical and Petrophysical Characterisation of Hydrocarbon Reservoirs in South China Sea Deep Water Block 29/26
Authors: Mi Greg Yanpeng 
Published: May 2013

Abstract
In 2004, Block 29/26 Production Sharing Contract (PSC) was signed between Husky Energy Inc. and China National Offshore Oil Corporation (CNOOC). The block is located about 300 km offshore Hong Kong (Figure 1), on the north east slope of the gas-prone Baiyun (White Cloud) Sub Sag of the Zhu-II sub-basin in the larger Pearl River Mouth Basin (PRMB). The water depth on the block is from 650 m to 1500 m.
A total of 27 deep water exploration and appraisal wells were drilled in the period between 2006 and 2011. Three commercial gas fields, Liwan 3-1-1, LH34-2 and LH29-1, were discovered in April 2006, September 2009 and December 2009, respectively. Several sub-economic gas accumulations were also discovered in the same period. Reservoir and hydrocarbon detection and trap delineation, were the key challenges faced by the exploration team. An integrated subsurface approach, including extensive 3D seismic surveying and high quality processing, seismic inversion, accurate structural/stratigraphic mapping, accurate depth conversion and seismic-based geomorphology, played a key role in making these discoveries. At the time of writing this paper, Block 29/26 is the only deep water block in South China Sea (SCS) with commercial discoveries, and boasts the most extensive deep water database in the region, including large amounts of seismic, conventional and side-wall cores, wireline logs, pressure and fluid samples as well as subsequent lab analyses data. Full investigation of the available information can be expected to provide the necessary guidance for future exploration and development activities in this region.
There are several types of reservoirs encountered in Block 29/26. Each type of reservoir has distinctively different log characteristics and seismic responses. This paper provides a systematic review on the applicability of AVA technology to the seismic data on the block and focuses on the challenges that need to be addressed in the future.
Study and Application of Production Relief and Blowdown on the Large-Scale Offshore Oil and Gas Fields
Authors: Zhi Xia 
Published: May 2013

Abstract
This paper discusses and summarizes the typical development engineering options about production relief and blowdown system, which based on the cases study of some large-scale offshore oil & gas fields in production worldwide and their features, functions and applications. The evaluation of flare system is based on safety, environment, constructability and cost effectiveness that safely minimize the flaring load. Total blowdown load could be further reduced by installation of Passive Fire Protection as fire proofing insulation but with higher CAPEX and OPEX cost. Generally, cold venting is not recommended especially for large scale offshore production due to safety concern and environment issues.
The Liwan3-1 gas field is located in the South China Sea, in approximately 1480 m of water depth, and 350 km far from the onshore. Total maximum yearly gas production gas project reaches 120×108 Sm3, and two flare systems are provided on the central platform. Various scenarios of relieving and depressuring cases are analyzed to determine the peak rate of each option. Depressuring or blowdown systems work in conjunction with the shutdown system is functioned to isolate and depressurize process systems in the event of a fire or incident where the process inventory is required to be removed. The high pressure and low pressure flare knock out drums are provided for both the HP and LP flare systems prior to gas disposal by combustion at the LP and HP flare tips. Both LP and HP flare system share a common flare boom, and high-integrity pressure protection system is applied to reduce the design capacity for the flare system. The flare radiation limit of 6.31kW/m2 is recommended and the mean wind speed is used as the criteria to be adhered to. The flare stack is designed for various orientations. The 45° inclined stack form horizontal is recommended based on safety concern as primary and cost.
According to the environmental conditions and the features of potential oil and gas structures in the South China Sea, the deepwater development engineering options of about production relief and blowdown system which will be suited for the area are proposed.
Husky Liwan Deepwater Subsea Control System
Authors: Bavidge Michael 
Published: May 2013

Abstract:
The Liwan subsea control system located offshore China in deepwater of 1,500 meters is one of the most technologically advanced systems to be installed. The control system for Liwan is of necessity large and complex and has incorporated many current industry innovations in control and communications across the system.
This paper will present a review of the control system and the key components provided for the deepwater Liwan field such as,Subsea Control Modules (SCM) for Subsea Production Trees and StructuresSubsea Router Modules (SRM) for Manifold, Pipeline End Manifold (PLEM) and Umbilical Termination UnitsSubsea Monitoring Module for Corrosion Monitoring SystemSubsea Power and Communications Unit located on the Central Production Platform (CEP)Chemical Injection Metering Valves for the methanol (MeOH), monoethylene glycol (MEG) and Corrosion Inhibitor (CI) distribution at the subsea structures.Umbilical Termination Units for Subsea DistributionUmbilical Termination Heads for the Infield Umbilical DistributionFiber Optic Communications from Topside to the SRM'sHigh Voltage Direct Current (DC) system to all SRM's and SCM's located on all structures
The development and engineering of the Liwan control system will be described within the paper from conceptual design, explaining the control system architecture due to the Liwan field layout complexity of area's Liwan 3–1 and Liuhua 34–2 and their distant geographical locations subsea. This paper will also cover the subsea control system fabrication, integration testing and finally installation and commissioning offshore in China.
Long Stroke Ram-Style Tensioner Technology
Authors: Koos John 
Published: May 2013

Abstract
The focus of this presentation will be to discuss and evaluate major concerns in the development of Long Stroke Ram-Style Tensioners, as an enabling technology to address the upcoming demands of the Offshore Industry as it pushes to drill and produce in ultra-deep water. The increasing demand on riser tensioners to accommodate higher riser loads with longer stroke capability in ultra-deep water is pushing technology beyond what has been currently developed in the industry.

Introduction
As Drilling and Production recovery for oil and gas expands into water depths in excess of 8,000ft, tensioner technology is being challenged to provide realistic and cost effective solutions. As riser tensioners increase in size and capacity to accommodate high riser loads, well bay configurations and tensioner interfaces have a significant impact on the design of the support vessel. Tensioner stroke lengths are increasing rapidly in response to larger vessel offsets, heave displacements and updated Regulatory requirements for survival conditions. These long stroke high capacity tensioners are influencing well bay design. Specifically, the stack up clearance between decks, number of risers, jumper hose layout, riser spacing, production tree clearance and motions, equipment maintenance and access. It takes an iterative design effort to integrate all of these elements into a cost effective workable solution.
There are two major tensioner configurations used in the industry today; the ram or push up style and the rod in tension or pull up style. Both tensioner styles have various pros and cons inherent in each configuration. Numerous factors are considered when selecting a tensioner for a particular project or vessel type such as operator preference, load ring accessibility, well bay configuration, tensioner capacity, component serviceability and cost.
Finneidfjord: a Field Laboratory for Integrated Submarine Slope Stability Assessments and Characterization of Landslide-Prone Sediments: A Review
Authors: Haflidason Haflidi , Morgan Eugene , L&apos;Heureux Jean-Sebastien , Forsberg Carl Fredrik , Kreiter Stefan , Kopf Achim , Lecomte Isabelle , Kvalstad Tore J. , Vardy Mark E. , Longva Oddvar , Brendryen Jo , Strout James Michael , Tobias Moerz , Vanneste Maarten , Steiner Alois 
Published: May 2013

Abstract
Sørfjord outside the village of Finneidfjord has a history of landsliding throughout the Holocene. The 1996 landslide -the focus of this study - has many characteristics typical of submarine landslides (well-developed slip plane, outrunner blocks, peripheral thrusting and lateral spreading). Due to its sheltered and accessible location, Finneidfjord has become a natural laboratory for testing high-resolution and multidisciplinary techniques to improve our understanding of landslide development.
This study integrates multiple sediment cores, swath-bathymetry surveys, single- and multi-channel 2D seismic data (Topas, boomer, sparker, airgun), very-high-resolution 3D chirp seismics, ocean-bottom seismometer as well as free fall and traditional cone penetration testing (CPTU). The cores have been subjected to both geological and geotechnical laboratory analyses. Of particular interest is the correlation of the regional slip plane as a high-amplitude package of reflections in the geophysical data with the results of the sediment and in situ measurements.
Comparison of 3D traces with synthetic seismograms based on multi-sensor core logs show that the most prominent slip plane lies within a thin clay unit sandwiching a sand seam. The slip plane is difficult to identify from CPTU data alone. The top part of this composite unit has in places been eroded under the 1996 mass-transport deposit (MTD). This composite unit's formation is associated with turbidite deposits from terrestrial quick clay landslides and possibly river floods in the catchment of the fjord. While the MTD is extensively deformed, different flow facies are identified within the landslide body revealing a complex, multi-phase failure. The seismic data were also used to infer physical properties (mean grain size, gas saturation from P-wave attenuation). Interestingly, shallow gas adjacent to the landslide appears not to have played a role in the landslide development.
Fjordbed stability is strongly influenced by shallow subsurface structure, with geotechnical properties and lateral continuity of stratified beds acting as primary controls on slide plane depth and failure mechanisms. This study can well form a template for near-shore areas prone to landsliding. Currently, a long-term pore pressure monitoring programme is in progress, after the installation of several piezometers close to the depths of the slip plane close to the shoreline in September 2012.
Gaps and Advancements for Deepwater Production and Remote Processing: Large Diameter Riser Laboratory Gas-Lift Tests
Authors: Schoppa Wade , Zabaras George J , Menon Raghu , Wicks Moye 
Published: May 2013

Abstract
An experimental program was carried out to support the application of riser-base gas injection for deepwater production risers. The experimental equipment consisted of a 40 ft-tall, 11?? ID vertical riser connected to a 25 ft-long flowline section of the same inside diameter. The motivation for this work was the significant uncertainty that exists as to the behavior of vertical gas-liquid flow in large diameter pipes. Scarce published information exists for such flows and no known records of flow regime observations are available from the published literature.
Riser-base gas-lift has been identified by various deepwater project teams as a key operability element that can address three major project objectives:flow assurance requirements necessitate the evacuation of the riser during an extended shut-down by using injection gas. As a result of riser evacuation, the hydrostatic pressure at the base of the riser is reduced to a level below the pressure required for hydrate formation at the ambient seawater temperature of between 37 and 40 F,production economics for many deepwater projects relies on riser-base gas-lift as an artificial lift method and,riser-base gas injection will be necessary for alleviating severe slugging problems in deepwater flowline-riser systems.
In order to verify the ability of gas-lift to fulfill the stated objectives for large diameter risers, a variety of air-water flow tests were carried out in the 11?? transparent riser system built at Shell's Houston Technology Center. The flow tests included transient and steady-state gas-liquid flow and flow regime visualization. Measured riser pressure drop data were used to compare with 1-dimensional flow model predictions. Serious model limitations were found as the models failed to accurately capture " churn flow" effects that appeared to dominate over the range of conditions studied. Steady-state pressure drops were underpredicted by more than 25%. Riser evacuation predictions indicated continued liquid removal whereas the data showed that liquid is expelled as an initial slug with no additional carry over.
To overcome the shortcomings of 1-dimensional models, rigorous analyses using Computational Fluid Dynamics (CFD) simulations were performed. A full 3-dimensional CFD model of the flowline-riser system was used in FLUENT with the volume of fluid (VOF) method to predict both steady-state and transient behavior. In all cases simulated, CFD results compared well with the experimental data.
A Simplified Approach to Modeling Long-Term Monopile Serviceability with Finite Element Analysis
Authors: Edgers Lewis , Bradshaw Aaron S. , Ebin Daniel 
Published: May 2013

Abstract
Monopile foundations for offshore wind turbines are subject to many cycles of large horizontal loads and overturning moments. This paper describes the foundation analysis of a wind turbine foundation typical of 3 to 5 MW units that have already been constructed in the southern North Sea and are being proposed offshore in the northeastern United States. The foundation consists of a 5.1 m diameter monopile driven 26 m below the seafloor into medium dense sand. The environmental loads were highly idealized, represented as a 6 MN vertical force and a 4 MN horizontal force applied 30 m above the seafloor. The effects of one cycle of monotonic loading and up to 107 cycles of long-term cyclic loading were computed. The analyses were performed using a widely available three-dimensional finite element program, incorporating an implicit method to model the soil modulus degradation and increased strain as a function of the number of loading cycles. The computations showed that the monopile displacements and rotations accumulate with additional cycles of loading, almost doubling after 107 cycles. This suggested that a monopile that rotates within tolerances after one cycle of load, approximately 0.25°, may accumulate unacceptably high deflections and rotations over its design life. The paper demonstrated the use of commercially available software as part of a method to model the response of a wind turbine monopile foundation to long-term lateral cyclic loading.

Introduction
A monopile is a large-diameter, open-ended pipe pile driven into the seafloor, connected to a wind turbine tower by means of a transition piece. The tower supports the turbine nacelle and the rotor. Monopiles must withstand the forces from wind, waves, ice, currents, and vessel impacts over the life of the turbine, which can be up to 50 years. The design of the monopiles must consider the response of the supporting soil to the long-term applied cyclic loadings. As such, an accurate method to calculate the lateral deflection and rotation of the pile due to cyclic loading, including the effects of changes in properties of the supporting soil, is needed. This study is concerned with the effects on offshore wind turbine foundations of high cycle, low amplitude loading that will induce small strains. It is assumed that the cyclic loading has low strain-amplitude, less than 10-3 (Whichtmann et al., 2010), with as many as 107 cycles over the lifetime of the offshore wind turbine (OWT), consistent with the observations by LeBlanc et al. (2010).
Monopiles are generally installed in water depths of less than 30 m (Malhotra, 2010). At greater depths, they become excessively large and uneconomical. Critical elements of their design include the loadings and performance requirements or limit states. One of the serviceability limits conditions is that a monopile cannot exceed a permanent rotation typically of 0.5° at the mudline level over its design life (Malhotra, 2010).
Tethered Catenary Riser: A Novel Concept for Ultradeep Water
Authors: Legras Jean-Luc 
Published: May 2013

Abstract
A new riser concept is proposed by Subsea 7 for field development in deep and ultradeep waters: the Tethered Catenary Riser (TCR)-patent pending. The concept consists of a number of steel catenary risers supported by a subsurface buoy which is tethered down to sea-bed by means of a single pipe tendon and anchored by means of a suction pile; flexible jumpers are used to make the connection between the Floating production Unit (FPU) and the buoy. Umbilicals run without interruption from the FPU to their subsea end while being supported by the buoy.
The system has all the advantages of de-coupled riser arrangements: flexible jumpers effectively absorb platform motions, thereby the rigid risers and tendon have very small dynamic excitation. The system can be installed before FPU arrival on site, which improves the time before first oil. Analyses have shown that, with adequate geometry of the buoy, the latter is sufficient stable to induce acceptable tilt and twist when different arrangements of SCRs and flexible jumpers are installed, and under accidental scenarios during the in-place life.
The riser system is best designed for a number of risers between 4 and 8, in addition to a number of umbilicals, thus convenient for one or two drilling centers.
Results of the basic engineering work on the TCR clearly indicate that it is possible to have a robust design using presently qualified materials and technology. The components used in the TCR are all field proven as they are commonly used in existing riser systems.
As a result of installation studies, a method very similar to the one commonly used by Subea7 for Single Hybrid Risers (SHRs) has been selected for the buoy and tether system. Placement of rigid risers, jumpers and umbilicals is as done by Subsea 7 for the BSRs. This method is well adapted for installation by the new Subsea 7 flagship vessel Seven Borealis which is able to perform heavy lift and pipe laying.
The Tether Catenary Riser is a credible option for use in deep water developments all over the world. Since all the components, design methods and installation procedures are fully qualified and familiar to Subsea 7, the concept is cost effective and ready for project application.

Introduction
A lot of well proven riser concepts have been used in deepwater for different environments, in particular, steel or flexible risers in catenary or lazy-wave shape, and single or bundle Hybrid Riser Towers (HRTs). Nevertheless, for some application new concepts are deemed more attractive and selected, as the Buoy Supporting Riser (BSR) for ultra-deep water offshore Brazil. But other ideas of riser concept emerge from the review and comparison of pros and cons of existing riser systems, trying to take the better of each one. The TCR is an adaptation of the BSR, but with a simpler tether arrangement and easier installation method. It can also be seen as a SHR with a number of SCRs attached to the buoyancy tank. The concept is described below as well as design methodology, application example and installation outline procedures.
A Risk-Based Approach To Managing the Integrity of an Ageing FPSO Hull
Authors: MacLean Calum , Hagood Scott 
Published: May 2013

Abstract
The hull of any FPSO not only provides the platform for the production facilities and accommodation, but also incorporates the storage and offloading facilities for the field (and potentially other fields). As such the hull acts as a vital "hub", critical to both the operation and export chain.
For FPSO's (like ships) there already exists an "experience based" prescriptive regime for integrity management of the hull structure (Class). This, however is based upon maintaining a minimum standard for a forecast window of only 2.5 to 5 years as per a trading oil tanker where opportunities to drydock the hull to carry out inspections and any required maintenance can easily be accommodated.
Adopting this approach without due consideration of the constraints of FPSO operations imports a significant risk to the viability of an asset and does not guarantee the avoidance of having to go to dry-dock.
Understanding the potential dangers of unquestioningly following Class rules and requirements, Hess have sought to adopt an alternative risk based approach to mitigate the risks to both integrity and operational functionality by proactively understanding the condition and limitations of the hull structure, putting in place an appropriate level of inspection, having robust assessment criteria and implementing increased inspection regimes or undertaking appropriate repairs to deficiencies identified in the hull structure.
This paper presents the journey travelled by Hess from prescriptive Class rules to a risk based Class regime from the period 2006 to present. It will describe the asset; discuss Class rules and a risk based approach to integrity; and then describe how these are applied to the FPSO Sendje Ceiba.

Hess Equatorial Guinea Overview
Hess Equatorial Guinea operates the Ceiba and Okume Field developments. The Ceiba Field is comprised of subsea well clusters producing to FPSO Sendje Ceiba where the production is processed, stored and then offloaded through a CALM buoy. This field commenced production in 2000 and the license to operate expires in 2029.
The Okume Field consists of 4 bottom founded platforms and 2 mini-TLP's. Okume production is fully processed prior to being exported via a 20 km pipeline to FPSO Sendje Ceiba for storage and offloading. This field commenced production in 2006 and the operating license will expire in 2032.
Combined production from the two developments peaked at approximately 120,000 BPD and is currently in the range of 90,000 BPD. The FPSO serves as the storage and export terminal for both the Ceiba and Okume developments with an effective crude oil storage capacity of 1.78 million barrels. Liftings (sales) are made in 1 million barrel parcels.
These developments are located offshore of the city of Bata which is located on the West African mainland just north of the equator as shown in Figure 1 below. The equatorial location of the developments results in a very benign operating environment devoid of named storms.