bluuebunny/crossref_metadata_2025_split huggingface dataset:
Global Screening of Gas Hydrates
Authors: Reichel Thomas , Gallagher Joseph W. 
Published: June 2014

Abstract
Gas hydrates have been identified as a possible future hydrocarbon resource. Within the exploration industry various projects have been established to further understand and advance this frontier concept. This presentation will give an overview of results from a recent global basin screening of gas hydrates. The main objective was to define and rank the world's most prospective areas. A conventional exploration risking approach was used to evaluate and risk both offshore and onshore basins for hydrocarbon source, gas migration pathways, reservoir properties and sealing capabilities of the sediments. Seismic data, well logs and other relevant data including public domain data have been analyzed. Approximately 500 onshore and offshore basins have been evaluated and ranked, several of which reveal good to very good gas hydrate potential. Data examples are presented to outline the approach taken in more detail and to illustrate some of the characteristics of typical prospective gas hydrate accumulations. Based on the results of this study, we believe we have localized some of the more interesting "sweet-spots" from an industry perspective. Technological developments, the gas price and the continued increase in demand for energy will define if and when these resources will be exploited on a large scale.
Long Term Deepwater Environmental Monitoring Off Angola - Data Management Strategy
Authors: Walls Anne , O'Brien Rob , Clarke Jim , Pereira Costa Sofia , Oliveira Shirley , Smith Ken , Priede Imants , Vardaro Michael , Rowe Gilbert , Bailey David , Milligan Rosanna , Ruhl Henry , Sangolay Bomba 
Published: June 2014

AbstractIn early 2009, two Deep-ocean Environmental Long-term Observatory Systems (DELOS) were installed in around 1,400m water depth in Block 18, Angola. The intention is that they will provide a unique long-term (25 year) dataset of deep-ocean variability. Each station consists of a fixed platform structure into which serviceable modules containing oceanographic, acoustic and camera equipment are placed. One monitoring station is located near to subsea infrastructure, and the other is located at the same depth but distant from, and upstream of, any oil industry activities. This far-field platform also has a sediment trap module. This will enable both long term natural and anthropogenic changes in the physical, chemical and biological environment to be identified and investigated. The data will also allow an understanding of the pace of recovery from unforeseen impacts and provide a linkage between marine biodiversity and climate change.An international scientific steering committee initially developed the DELOS concept and specified the equipment. It now oversees the research associated with data interpretation.The modules are recovered approximately every twelve months, and the data downloaded, batteries changed and the equipment serviced before being returned to the seabed. This paper will discuss the pros and cons of the intermittent data collection and how the data are managed and interpreted, including sharing with our Angolan partners.
Highest Reliability Provides World Class Benchmark for Permanent Downhole Monitoring Installation and Data Delivery in Malaysia
Authors: Samuel Orient B. , Khalid M. Zaidan , Raw Ian , Singh Premjit Kaur Kaka 
Published: June 2014

Abstract
Reservoir pressure and temperature measurements have become the cornerstone of reservoir and production management. These measurements provide improved capabilities for understanding of oil and gas reservoir characteristics, which enables greater reservoir management for increased production and improved ultimate recovery.'
The reliability and accuracy of permanent downhole pressure and temperature technologies is therefore of the highest priority when planning field developments, be it green fields, brown fields, marginal fields or EOR projects. A long term Permanent Downhole Gauge and Fiber Optic monitoring contract was awarded in August 2010 with the intent to provide reservoir monitoring with the highest reliability and accuracy that was available. Since the award of the contract, the world-class milestone of 50 installations was achieved in August 2013. This milestone has been enhanced by the fact that to date, an amazing success rate of 100% has been realized.
This success story has been achieved by a combination of many factors, from the strong validation process for gauge selection and subsequent choice of world class technologies with the highest survivability in the oil industry, close collaboration between the project and operations teams of the oil company and service provider, project management expertise, detailed preparation and maintenance, to the philosophy of providing real time data delivery to the end user.
This paper highlights the technologies installed and processes charted over the last three years to achieve this remarkable success story.
Variation of Asphaltene Onset Pressure Due to Reservoir Fluid Disequilibrium
Authors: Chen Yi , Wang Kang , Chen Li , Dumont Hadrien , Mishra Vinay K. , Zuo Julian Y. , Mullins Oliver C. , Elshahawi Hani 
Published: June 2014

AbstractReservoir fluids in a single compartment can be in a state of gross thermodynamic disequilibrium. The equilibration of reservoir fluids is a slow process in part mediated via diffusion, an inherently very slow process. When reservoir fluids are subjected to other, faster processes, equilibration can be precluded. A common event in reservoirs especially in deepwater is a late gas charge into an oil-filled reservoir. In this case, the gas can quickly migrate to the top of the reservoir through fault planes without mixing with the existing reservoir fluid. This newly charge gas can then diffuse down into the oil column thereby creating very large gradients of many fluid properties such as gas-oil ratio (GOR) and bubble point pressures. In addition, asphaltene solubility is highly sensitive to GOR (as shown in the Flory-Huggins-Zuo Equation of State (FHZ EoS)), thus very large gradients of asphaltene content can likewise be established. Where solution gas is high, asphaltene instability is expected and Flow Assurance problems can occur. Gravity segregation of asphaltenes due to redistribution of the colloidal speciation of the asphaltenes in accordance with the Yen-Mullins Model can occur and results in asphaltene gravity currents. This process can result in significant variations in asphaltene concentration throughout the column. This convective process can yield large asphaltene concentrations at the base of the column thereby producing corresponding Flow Assurance concerns at the base. The combination of all these processes associated with gas charge into black oil can create a large gradient in asphaltene onset pressure (AOP). Such cases if not properly analyzed can give rise to mismanagement of Flow Assurance concerns. In this paper, we discuss case studies that exhibit such potentially problematic fluid columns. Simulated cases are also modeled to provide guidance for optimal management of AOP variations. The relationships of these Flow Assurance problems with other production problems are clarified. The ability to model asphaltene gradients with the FHZ EoS is seen to help significantly in understanding of asphaltene phase behavior of reservoir fluids.
Reservoir Controls on the Occurrence and Production of Gas Hydrates in Nature
Authors: Collett Timothy S. 
Published: June 2014

Abstract
Gas hydrates in both arctic permafrost regions and deep marine settings can occur at high concentrations in sand-dominated reservoirs, which have been the focus of gas hydrate exploration and production studies in northern Alaska and Canada, and offshore in the Gulf of Mexico, off the southeastern coast of Japan, in the Ulleung Basin off the east coast of the Korean Peninsula, and along the eastern margin of India. Production testing and modeling have shown that concentrated gas hydrate occurrences in sand reservoirs are conducive to existing well-based production technologies.
Because conventional production technologies favor sand-dominated gas hydrate reservoirs, sand reservoirs are considered to be the most viable economic target for gas hydrate production and will be the focus of most future gas hydrate exploration and development projects. For both Arctic and marine hydrate-bearing sand reservoirs, it is generally accepted there are no apparent technical roadblocks to resource extraction; the remaining resource issues deal mostly with the economics of hydrate extraction.
Dual Gradient Drilling Is Ready For Primetime: The Benefits Of A Retrofit System For Better Well Control, Enhanced Water Depth Capability And Flat Time Reduction
Authors: Ziegler Robert 
Published: June 2014

Abstract
A very large number of newbuilt deepwater rigs has recently entered the fleet. While a lot of innovation has been achieved in the area of pipe & riser handling, the actual drilling process has not changed much compared to earlier rig generations. Among the leading deepwater drilling operators, the need for managed pressure drilling in deepwater becomes more and more apparent, given the type of wells that need to be drilled now and in the future. Dual Gradient drilling takes advantage of the long riser in the water column as a tool for managed pressure drilling, and so has emerged as a very desirable way of implementing MPD in deepwater. This paper demonstrates that such dual gradient capabilities also can be retrofitted to the existing rigs with no need to go to a shipyard, and thus not necessarily only can be incorporated when the rig is originally built. A field-proven retrofit dual gradient system using electrically powered mid-level riser pumping technology is presented. The benefits of such a system specifically for retrofitting existing deepwater rigs are described, The difference in pressure gradients in between such a pumped riser system and a backpressure (RCD) managed pressure system are shown. Specifically the areas of enhanced well control and kick recovery, water depth capability increase and significant operational flat time reduction are elaborated on. Capability envelopes with one and two pump skids on the riser are shown. The benefits of combining the controlled fluid level in the riser with a continuous circulation system are demonstrated. Finally, an overview of the steps required for retrofitting such a system to a typical deepwater rig are described, with a 6th generation rig used as an actual example. One such retrofit has already been performed and successfully used in the field on 3 commercial ultradeepwater exploration wells in a remote area of the Gulf of Mexico.
Overview and Assessment of Vertical Transport Systems
Authors: Boomsma Wiebe , Blanken Amir 
Published: June 2014

Abstract
To fulfill our need for raw materials for a growing world population and increasing demand per person, especially for the developing countries the step to deep sea mining seem to be inevitable. A deep sea mining operation typically consists of a seafloor mining tool for excavation or gathering of material, a vertical transport system to transport the material to the sea surface and a floating structure of vessel with optional processing. The success of a deep sea mining operation will strongly depend on the proper choice of the right equipment and a solid knowledge of all aspects of the mining system. In this paper emphasis is placed on the Vertical Transport System. There are several concepts for vertical transport systems possible, this paper describes several of them, like a batch system, [an airlift system and vertical transport systems using either centrifugal or positive displacement pumps and states their pros and cons. Furthermore recent developments for VTS technology within the IHC Merwede group are described.
An Evaluation of Large Capacity Processing Units for Ultra Deep Water and High GOR Oil Fields
Authors: Capeleiro Pinto Antonio Carlos , Martins Vaz Célio Eduardo , Moreira Branco Celso Cesar , Ribeiro Jônatas 
Published: June 2014

Abstract
A study of offshore production units with large fluids processing capacity is presented, focusing in ultra deep water scenario (higher than 2,000 m) and the production of light oil, with high Gas Oil Ratio (GOR) and CO2 contamination. This situation fits to some exploratory and production areas offshore Brazil.
Taking a regular size FPSO as the comparative base, analysis explored the impacts of different processing capacities on energy demand, weight and footprint requirements. The evaluation considered two gas processing plants: the first is less complex, without CO2 separation from the produced gas, reinjecting the whole produced gas into the reservoir; the second is more complex, with CO2 removal and a more flexible plant, capable of exporting treated gas and reinjecting rich CO2 stream or the whole gas. As the driving force of CO2 separation by membranes is the pressure drop between feed gas and the permeated rich CO2 stream, the second option leads to a lower processing capacity, mainly due to the increase in compression and power demand. The risks and benefits of large production systems are also evaluated from the reservoir drainage and gathering systems point of view.
One of the main constraints is the indication that for high GOR oil, considering or not CO2 separation in the processing plant, its capacity would have to be limited due to maximum topside dry weight and deck footprint that could be installed on a converted hull or a new built unit. Additionally, constraints related to maximum power generation must be taken into account. If CO2 is not removed, and the gas is reinjected with no export, a higher processing capacity could be achieved. The design of higher capacity plants shall also consider reservoir aspects, flow assurance through long tie back wells, operability, maintainability and increase in difficulty to purchase high capacity equipment, such as vessels, valves, pumps, compressors and other.
Human Factors in Hazard Analysis
Authors: Poblete Benjamin R. , Parker Christopher W. , Ranasinghe Sam , Gandhi Minu Shikha 
Published: June 2014

Abstract
This paper will provide a practical overview, based on the authors' field lifecycle experiences, to the consideration of Human Factors in hazard analyses to support the design and operation of oil and gas installations. In the development of oil and gas projects, human factors issues is informally addressed through the design development but recently the US Bureau of Safety and Environmental Enforcement's (BSEE) promulgated the rule on Safety Environment Management Systems (SEMS), API RP 75, in 2010, which now formally recognizes human factor during design lifecycle.
In particular, for the element of hazard analysis the SEMS regulation states, "human factors should be considered in this analysis". Over the last 10–15 years, there have been industry papers that have discussed this topic at a high level, mostly about integration with Hazards and Operability Studies (HAZOPs). However, Oil & Gas Producers (OGP) Report No. 454, Human Factors Engineering in Projects (2011) provides appropriate guidance within the HAZOP framework to address human factors in hazard analysis.
Despite this history and guidance, it is evident that the lessons learned during the application of HFE in design continue to evolve with more engineering design. This paper discussed the OGP report and other guidance on Human Factors in hazard analysis along with practical lessons learned and challenges from the authors' experiences on major offshore design projects on a range of hazard analyses such as HAZOPs, Hazard Identification Studies (HAZIDs), Qualitative Risk Assessments (QRAs) and Escape, Evacuation and Rescue Analyses (EERAs), etc. The challenge continues in integrating more HFE during hazard and risk management activities in all engineering design activities. This paper has provided the impetus, guidance and momentum to address the human element in hazard analysis during the design of oil and gas facilities; this is just "the tip of the spear".
Sealing Material Performance Gaps in Ultra-HP/HT Applications
Authors: Ren Jiaxiang (Jason) , Gerrard David 
Published: June 2014

Abstract
Emerging unconventional oil and gas operations, deepwater drilling and completion operations, steam-assisted gravity drainage (SAGD), and geothermal applications require sealing materials to withstand ultra-high pressures and temperatures (ultra-HP/HT), in harsh downhole environments. These conditions push the known performance limits of proven downhole sealing materials such as polyetheretherketones (PEEK) and perfluoroelastomers (FFKM). To identify the possible performance gaps of these materials in ultra-HP/HT conditions, high-temperature aging tests were performed in several common fluids encountered downhole. The material response to the various exposures were characterized using tensile testing, dynamic mechanical analysis (DMA), differential scanning calorimetry (DSC), and Fourier transform infrared spectrometry (FT-IR). Some results were surprising. For example, a significant degradation was observed for PEEK when aged in either a completion fluid at 260°C (500°F). The test results have helped define new application windows for the materials that were tested.
Settlement Prediction In The Ulleung Basin Due To Gas Hydrate Production
Authors: Kim A. R. , Cho G. C. , Song K. I. , Kim S. J. 
Published: June 2014

Abstract
The potential existence of methane hydrate deposits in the Ulleung Basin of the Korean East Sea was suggested by the Korea Institute of Geoscience and Mineral Resources between 2000 and 2004 and a pilot production project is planned for 2015 as the world's second offshore hydrate production project. The basin has a water depth of 1500–2300 m; however, the depth of the hydrate occurrence zone is relatively shallow (about 100–200 MBSF) for gas hydrate production. There is high potential for geomechanical stability problems such as marine landslides, seafloor subsidence, and wellbore instability. In this study, 2D axisymmetric numerical modeling is conducted to simulate gas hydrate production from the Ulleung basin by depressurization. The simulation incorporates the physical processes of hydrate dissociation, the pore fluid flow and the geomechanical response of hydrate-bearing sediments. During depressurization, deformation of sediments around a production well is generated by the pore pressure difference in the depressurized and dissociation region. This tendency becomes more pronounced due to a stiffness decrease of hydrate-bearing sediments caused by hydrate dissociation.
Exploring Genesis Potential Indices
Authors: Bruyère C.L. , Holland G.J. 
Published: June 2014

AbstractThat the large-scale environment has a role in determining tropical cyclone genesis has been understood since the earliest analyses of the association between cyclones and the general circulation in the tropics. Gray (1968, 1979) summarized the state of science and demonstrated the potential for assessing genesis potential utilizing such environmental parameters as ocean thermal content, midlevel moisture, an unstable atmosphere, low-level vorticity, and vertical wind shear through a deep atmospheric layer. Building on this earlier work, a number of cyclone genesis indices have been developed and are being utilized to assess potential hurricane changes over climate time-scales. A recent index developed for North Atlantic tropical cyclones combines an index of available energy for cyclone development with the negative influences of strong vertical shear and has demonstrated skill in assessing annual cyclone frequency variations (Bruyère et al., 2012). Following on from this study, here we examine a number of global cyclone regions with the goal of establishing similar predictors of annual cyclone counts.
A Deepwater Sandface Monitoring System for Offshore Gas Hydrate
Authors: Chee S. , Leokprasirtkul T. , Kanno T. , Osawa O. , Sudo Y. , Takekoshi M. , Yu H. , Yamamoto K. 
Published: June 2014

Abstract
The world's first offshore gas hydrate production was successfully carried out in the deepwater Japan at Nankai Troughin Q1 2013. In this project, one production well and two sandface monitoring wells were drilled and installed with a combination of distributed temperature sensing (DTS) and array-type RTD (Resistance Temperature Detector) sensors.
The objective of the sandface monitoring system was to capture the hydrate dissociation front dynamically changing during the production test and to monitor long-term reservoir stability with the selected temperature sensors. An ability to continuously monitor the response of these temperature data during production test would facilitate tracking of the dissociation front and yield valuable information for engineering design and verification of numerical reservoir simulators. The temperature sensors are cemented behind the casing and also strategically installed to cover the hydrate zone of interest and the entire wellbore. Due to operational constraints, the monitoring system was designed to be autonomous self-operated system by the subsea battery without cable connection from the sea surface for a period of 18 months from the day of installation of the monitoring system.
The deployment of this monitoring system in this shallow unconsolidated hydrate reservoir was an unprecedented and challenging operation. In this paper, we will show the details of the key system components of the sandface monitoring system and the deployment process.
Offshore Application of a Novel Approach to the Inspection of Flexible Risers
Authors: Kershaw K. , Binny W. , McCarthy J. , Buttle D. , Eckold G. 
Published: June 2014

Abstract
The inspection of unbonded flexible risers poses a number of challenges several of which are linked to the complex nature of the pipe's construction. This precludes the application of most conventional inspection techniques. Further difficulties arise because in many cases the critical region of the riser is at the top end; from the splash zone to the termination. This area is particularly congested where the presence of the bend stiffener and I-tube structures means there is no access for inspection equipment.
This paper describes a unique inspection approach which overcomes these challenges and its implementation on an FPSO operating in the UKCS by Shell. The inspection technique concerned employs electromagnetic stress measurement technology that when mounted onto the external surface of the riser can sense into the riser construction and measure the stress in the tensile and pressure armour wire layers, the primary load bearing elements within the riser design. From this information the integrity of these layers such as the presence of wire breaks can be determined. A key feature of the approach is the concept of ‘reach’. As the layers within the pipe wall are unbonded the effect of a wire break can be seen many metres away from the location of the break itself: so an inspection at a single location can determine the state of the riser armour wires over the complete length of the critical top section.
The application on the FPSO formed part of Shell's riser integrity management and life extension programme. A simple scanning device was deployed allowing a stress measurement probe to sense the state of all of the armour wires in the riser from a single point in the turret region. The results of the scan demonstrated that the armour wires of the riser were in a sound condition for continued service. This paper will provide the background to the underlying technology and its embodiment within an inspection system, together with the results from the inspection campaign.