bluuebunny/crossref_metadata_2025 huggingface dataset:
Black Ore Cultivation Program in the Okinawa Trough
Authors: Saruhashi T. , Kyo M. , Sawada I. , Nozaki T. , Yokoyama T. , Seneviratne C. , Lim A.C. , Goi K.K , Teo S.G.
Published: June 2014

JAMSTEC has an international patent for the environmentally-friendly cultivation system of hydrothermal chimney as the accessory product of scientific drilling program in the Okinawa Trough. We introduce the characteristics of natural and artificial hydrothermal vents in the Okinawa Trough, how this field was developed with special devices in the IODP Exp. 331, and new findings which lead to black ore cultivation system.

The topography around the hydrothermal vent was not flat surface in which conventional drilling guidebases cannot be used. A special guidebase, capable of inclinations up to 30 deg, was required for surface coring. The other challenge is the continuous flow from the hydrothermal vent whose maximum fluid temperature excessed 300 °C. Our research plan was to drill and cut the core through the guidebase, and set casing pipe and wellhead cap to collect pristine hydrothermal fluid by ROV.

The drilling and coring were successfully conducted through the guidebase deployed at 1000 mbsf (meter below sea floor). The retrieved core had high content of H2S gases which imposed us to wear breathing apparatus. Due to the high flow rate of 300 °C hotwater, the conventional bitumen core liners rapidly disintegrated. The hotwater producing from the top of wellhead cap has been vigorous with high flow rate in at least two years. The most remarkable finding was the highly rapid growth of sulfide chimney mainly composed of sphalerite, chalcopyrite and galena. After 25 months from the drilling, this sulfide chimney whose metal grade is higher than that of black-ore on land has grown to be 15 m in height. A new development plan was initiated to aim the cultivation of the chimney and efficient ore recovery. A custom-ordered cultivation tree attached to the wellhead cap is currently being developed.

JAMSTEC is planning to have the future expedition to launch the cultivation system at the Okinawa Trough for existing and additional wellhead. This expedition will focus on cultivation of the black ore from hydrothermal vent. The future planning of this project is also discussed in this paper.
Global Screening of Gas Hydrates
Authors: Reichel Thomas , Gallagher Joseph W.
Published: June 2014

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

In 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

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

Reservoir 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

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

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

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

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

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

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

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

That 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

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

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.
Development and Implementation of a High Temperature and Salinity Tolerant Kinetic Hydrate Inhibitor to Replace an Existing, Ten-Year Continuous Application
Authors: Webber Peter , Morales Noah , Madden Audrey
Published: June 2014

An operator in the North Sea has successfully employed a kinetic hydrate inhibitor (KHI) for over a decade. This operator produces through two 13 mile flowlines, separated into wet gas and fluids, to a multiphase host facility. At this host facility, the two production streams recombine in a slug catcher upstream of the separation system. The wet gas line operates continuously under conditions of hydrate stability requiring the use of a KHI. As additional wells have been tied into the subsea production stream, conditions have changed necessitating advancement in KHI technology.

The new production introduces formation water of considerable salinity into the production stream as well as increasing the temperature of commingled fluids in the slug catcher. As KHI polymers possess inverse solubility profiles with respect to temperature and salinity, gunking was frequently observed in the production slug catcher. The precipitated polymer, in addition to sand and organic solids in the system, caused frequent upsets and deferred production. Accordingly, a KHI polymer with improved solubility profile (cloud point) was targeted for this application. The KHI performance and compatibility with incumbent corrosion inhibitor were confirmed and optimized to a 50% reduction in treatment rate by autoclave experiments under the established qualification protocols. Solubility experiments confirmed the compatibility of the new KHI with the expected temperature and salinity parameters of the full production.

This paper provides a detailed history of this 10+ year application, recent qualification process, and field application of this new KHI offering.
Failure mechanism of cutting submerged frozen clay in an arctic trenching process
Authors: Liefferink D.M. , Grima M. Alvarez , Miedema S. , Plat R. , Rhee C. van
Published: June 2014

Pipelines in Arctic regions are at risk of being damaged by gouging ice masses(gouge depths of 5m-8.5m). As protection, pipelines can be buried in trenches. When trenching is performed in Arctic soil, subsea permafrost may be encountered. Subsea permafrost is found in the continental shelves of the Arctic seas at water depths up to 100 m. The upper units (the first 1m to 100m)generally comprise thawed layers, which act as an insulating layer to the permafrost below. Layers of thawed clayey soil have better insulating properties than those of coarser material. Consequently, more shallow subsea permafrost, which is located in the top 10 m of the seabed, is most likely to be encountered in clayey soils. Ground deformation caused by seabed ice gouges will demand that pipeline trenches be excavated up to 10 m deep. This leads to the conclusion that permafrost in arctic areas can be encountered while trenching, mainly while excavating clayey soil.

For proper design and construction of efficient subsea excavation equipment (subsea trenchers) thorough knowledge of physical characteristics of permafrost is necessary, and failure mechanisms, cutting forces and other important parameters should be assessed. A literature review identified that knowledge of excavation in permafrost is limited. Therefore Delft University of Technology and IHC Merwede joined forces to fill the knowledge gap.

The main goal of this research is to identify the governing failure mechanism of frozen clay. Knowledge of the failure mechanism of a material under certain cutting conditions leads to the ability to calculate cutting forces in similar conditions and to determine the required cutting energy per cubic meter of material, which is an essential parameters during design and operation of arctic trenchers.

This study found that frozen clay has a tensile and compressive strength comparable to soft rock. During the process of freezing, ice lenses are formed in clay, making the material inhomogeneous and anisotropic. The failure mechanism of frozen clay in an arctic trenching process is studied experimentally by means of a linear cutting test setup. Samples of undisturbed Dutch river clay were excavated, frozen and cutin submerged conditions at near atmospheric pressure. The observed failure mechanism of submerged frozen clay appeared predominately tensile brittle. Further research has been planned to obtain more accurate characteristics by using clay from Arctic areas, and conducting experiments carried under higher hydrostatic pressures.
Design Validation of the Caesar-Tonga Steel Lazy-Wave Risers using Field Data
Authors: Kumar Das Ajoy , Balch Erin , Group Kenny Wood , Fowler Sam , Yiu Flora , Beattie Michael
Published: June 2014

Offshore production risers are generally designed considering a large margin of conservatism to account for the uncertainty in the design parameters and to ensure robust design. As the Oil & Gas Industry is advancing toward ultra-deepwater there may be a necessity to adopt new technologies and riser configurations to develop the field. Project teams may elect to quantify the degree of conservatism in the designs as an additional measure to improve confidence in the safe and reliable service over the life of the field. Such validation provides confidence in the design performed based on theoretical concepts and software predictions.

This paper presents a novel approach that has been undertaken to validate the design of the Caesar-Tonga Steel Lazy Wave Risers (SLWR) tied back to the Anadarko Petroleum Company (APC) operated Constitution Spar located in the Green Canyon Area of the Gulf of Mexico. These risers represent the first application of the steel lazy wave riser technology in the Gulf of Mexico, and it was the first such application tied back to a spar platform.

The procedure is based on the monitoring of motion and strain data measured at critical locations along the risers. The measured data is post-processed to identify significant riser motion events that occurred during the observation period. Met- ocean data during this time period is also evaluated to correlate back to the riser motion events. Vessel motions and current data corresponding to these identified events are used to drive a Finite Element (FE) model of the riser, and the corresponding riser motions and strains are calculated. The calculated motions and strains are compared with measured motions and strains to provide confidence in the design methodologies. The procedure as well as the results of the comparison between predicted performance and measured performance is discussed in detail in the paper. The procedure can be applied for design validation and performance and integrity assessment of newly-built or existing risers.
Design Method and LRFD for HPHT Subsea Equipment for Extreme and Survival Load Conditions
Authors: Pathak Parth D. , Taylor Samuel L.
Published: June 2014

The current API standards and technical reports for Subsea Equipment which fall under API SC 17; especially relevant to Subsea Trees and Wellheads; do not particularly provide the design methods for Extreme and Survival load conditions. As the industry continues moving forward with the High Pressure High Temperature (HPHT) application it has increased the attention towards safety, and design precautions have the utmost priority. Hence, the industry is redoubling its focus on the Extreme and Survival load conditions for the Subsea Equipment, especially for HPHT conditions.

The recently published API TR 1PER15K-1 and in-work API TR 17TR8 address the design methods for Subsea HPHT equipment but do not specifically provide the design methods for Extreme and Survival load conditions. API RP 17G, recommended practice for completion/workover risers addresses these loading scenarios by providing the design condition factors, but suggests testing for plastic collapse load. API RP 2RD, recommended practice for Design of Risers for Floating Production Systems and Tension-Leg Platforms, recommends the consideration of these load conditions, but does not provide specific design rules.

This paper posits a design method for Subsea Equipment governed by API SC 17 particularly for API 17D, Subsea Trees and Wellhead under Extreme and Survival Load conditions. The proposed method combines the Elastic-Plastic design analysis method from ASME Boiler and Pressure Vessel Code (BPVC), Section VIII, Div. 2 and 3 and the API RP 17G Structural Resistance Methods. It combines the API RP 17G Design Condition Factors with the ASME Section VIII BPVC Div. 2 and 3, Load and Resistance Factor for Design (LRFD) to establish new LRFDs for Extreme and Survival Load conditions. Fatigue life estimation is also addressed for these conditions. An example analysis of a Subsea Tree component is reviewed, evaluating its combined load capacity for normal, extreme and survival conditions. Additionally, the review includes the fatigue life cycle estimation for this component.
Evolution of High-Pressure, Flexible-Capacity Air Compressors To Convert Smaller Vessels for Use in Marine Seismic Exploration Industry
Authors: Dorran Dan
Published: June 2014

The development, manufacture, maintenance and service of high-pressure compressors that can satisfy environmental, safety and reliability demands throughout offshore oil and gas discovery and production processes present manufacturers with significant challenges. Specialized, rent- and lease-ready compressors must fit the limited working environment of smaller vessels in seismic exploration applications yet have the reliability of a fixed, stationary compressor. Manufacturers are also challenged by the slow development of new acquisition technology to address air gun seismic concerns arising from marine life health issues.

Input from endusers and air gun suppliers, and commitment to the customer by the compressor manufacturer, will match forecast demand. This paper will detail the evolution of this class of compressor and the manufacturing challenges it entails.
Risks and Impact Assessment for Deepwater and Ultra-Deepwater Gulf of Mexico Resources
Authors: Rose K. , Aminzadeh F. , Ghanem R. , Thimmisetty C. , Jabbari N. , Khodabakhshnejad A. , Sim L. , Bauer J. , MacKenzie Mark-Moser , Disenhof C.
Published: June 2014

Recent natural and anthropogenic events, such as Hurricanes Katrina and Rita and the Deepwater Horizon oil spill, have identified significant gaps in our ability to predict risks associated with offshore hydrocarbon production as well as our capabilities to respond to deleterious events of varying scope, magnitude, and duration. As offshore hydrocarbon development in the Gulf of Mexico continues to push into new territory, there is a need to develop computational tools that enable the rapid prediction of outcomes associated with unexpected hydrocarbon release events from deepwater and ultra-deepwater systems in the Gulf of Mexico. To date, no comprehensive system-wide tool exists that can simulate the complexities of engineered-natural systems and provide the baseline data that is required to drive the simulations.

To address this gap, we are developing the Gulf of Mexico Integrated Assessment Model (GOM IAM), the first coordinated platform that will allow for independent, rapid-response, and science based predictions providing the capabilities to assess risks and potential impacts associated with deep and ultra-deep water drilling in the Gulf of Mexico. This predictive model and its analyses allow for the assessment and quantification of risks and environmental impacts from deepwater and ultra-deepwater oil and gas drilling and production, as well as provide a robust tool and database that can provide crucial information necessary for the response and recovery following future loss of control events. Once the GOM IAM is developed, it can be utilize to:identify potential risks;identify technology gaps,improve our understanding of the degree of uncertainty relative to key systems and interactions associated with deep and ultra-deep water offshore hydrocarbon development to promote safer development and operations, and iv) run scenarios to serve as a baseline rapid response tool for any future oil spill events.
Pumping Hydrate Slurries in the Arctic: A Different Perspective
Authors: Abulnaga Baha , Prescott Neal , Mantha Aishwarya
Published: June 2014

The formation of hydrates in oil-dominated production systems is a hazard that may potentially lead to the plugging of pipelines in deepwater and Arctic environments. Anti-agglomeration additives have been used in the field as a mitigation strategy to prevent hydrates from growing into plugs. Studies have dealt with the ability of certain crudes to form stable water in oil emulsions. These stable emulsions have been proposed to be made in-situ with or without chemical additives. In recent years, an emphasis has been made to understand the mechanism of formation of stable hydrates that can be transported in a slurry form. In order to achieve this in the field, extensive work has been done to mathematically model hydrate formation and agglomeration with the aim to understand transportation of hydrates as a slurry mixture without plugging. One critical aspect to the slurry mixture is the complex slurry rheology which is dependent on the volume concentration of solids, that can include both hydrates and precipitated asphaltenes, but is further complicated by the crystallization of hydrates by contact with a water droplet, and the growth into hydrates aggregates by agglomeration.

The mining industry has been able to transport complex mixtures and operate without plugging in pipelines covering over distances from a few kilometers to 1000 km. The viscosity for non-Newtonian laminar flows is often dependant on the shear rate and volume concentration of solids. The yield stress for a Bingham mixture is controlled by additives. In recent years, the oil sands industry has developed better knowledge of the pumping of oil, bitumen mixtures often called "oil sand froth". Learnings have included velocity induced lubrication of pipe walls by forming a water layer or "self-lubricated" pipe flow, achieving lower friction than predicted by traditional models of viscosity mixing between two liquids.

While the mechanisms of hydrate formation and agglomeration are different from traditional mining slurry, there are numerous practices from mining that can be applied to the pumping of stable hydrates; such as control of additives, control of shear rate, transition from a laminar to a turbulent regime, and self-lubrication of water-oil mixtures. In this paper the authors review some of the issues of hydrate formation, explore some efforts by researchers to understand hydrate-based slurry mixtures and propose some comparisons with the handling of mineral based slurry mixtures and nuclear waste slurry mixtures to formulate a concept of stable flow without plugging.
System Response During Short- and Long-Term Gas Production from a Gas Hydrate Deposit at the Site of a Planned Field Test in the Ulleung Basin of the Korean East Sea
Authors: Moridis George J. , Kim Jihoon , Reagan Matthew T. , Kim Se-Joon
Published: June 2014

We investigate by means of numerical simulation the coupled flow and geomechanical system behavior during gas production from an oceanic hydrate accumulation at the site of a planned field test at the Ulleung basin in the Korean East Sea. We study the system response at two time scales: a short period (14 days) that corresponds to the duration of the planned field test, and a prolonged production period that continues to the point of hydrate exhaustion and/or reservoir abandonment. The data describing the geologic model and the system properties were obtained from earlier geophysical studies and the analysis of cores obtained from experimental wells at several locations in the Ulleung Basin. Gas hydrate accumulations at this site typically occur in deep water (2157 m) but close to the ocean floor (with their tops 140 mbsf), and are usually characterized by alternating mud (nearly hydrate-free) and sand (hydrate-rich) layers. The layered stratigraphy and the presence of mud layers preclude the use of horizontal wells and necessitate vertical wells. The analysis of the short-term production tests focuses on the expected gas production rate and the possibility of subsidence during the limited time of the planned test. The long-term study aims to address the issue of feasibility of long-term production from the hydrates at the test site in terms of production rates and the geomechanical stability of the well assembly and of the reservoir. We investigate several well operation regimes. We evaluate the sensitivity of the system to various flow, thermal, and geomechanical properties, and we account for the interdependence of flow and geomechanical properties. We estimate possible subsidence under production and we determine the conditions that have the potential to lead to wellbore and formation failure, thus defining the envelope of well operations and production conditions that maximize safe gas production.
API Subcommittee 17 "Subsea Production Equipment" - Development of Industry Standards for Subsea Systems
Authors: Bednar John M.
Published: June 2014

The use of subsea production system technologies to produce hydrocarbons from deepwater environments worldwide continues to grow dramatically. Accordingly, industry's ability to utilize standardized subsea equipment designs and procedures can enhance the ability to do so in a safe, cost-effective, and reliable manner. API Subcommittee 17 " Subsea Production Equipment" (SC17) has maintained an evergreen effort to develop and maintain these subsea standards by providing the following:? A forum for industry discussion? A platform on which to foster consensus? Task groups that volunteer to generate respective documents? Multi-disciplined support from industry experts? An interface network with regulatory agencies to facilitate subsequent acceptance.

The continually evolving nature of subsea-related technologyposes a challenge to the SC17 membership to identify the need for new standards as the individual subsea-related technologies mature.

Provided below is an overview of the suite of documents that reside within the SC17 portfolio of standards, with special emphasis on those documents that are currently evolving. Also provided is a description of the API organization and processes that are employed in developing new standards and regularly updating/revising existing standards.
Lateral Buckling of Pipelines in Deepwater GoM
Authors: Hoor Azadeh , Singh Shilpa , Baxter Finlay , Jesudasen Sandeep , Zeng Wilson , Simpson Neil , Watson Ryan , Krishnappa Nag
Published: June 2014

The majority of the deepwater pipelines operating in the Gulf of Mexico (GoM) carry hydrocarbons at a high pressure and temperature resulting in the system's thermal expansion. In order to relieve the high stresses due to thermal expansion, these pipelines are designed to use buckle triggers in order to buckle laterally at pre-determined locations. Since these assets are expected to last a few decades, it is imperative that a robust long-term integrity management program is in place to effectively operate these pipelines, monitor their long term performance, verify design assumptions and thus, reduce any potential risks.

As a part of BP's comprehensive In Water Integrity Management (IWIM) program, three pipelines were surveyed during a 2012 Multi-Beam Echosounder (MBES) survey campaign. The surveys checked for buckle initiation, buckle locations and obtained accurate buckle shapes to allow subsequent integrity assessments to be performed. Ten out of ten planned buckles formed across the three operational pipelines; a mixture of sleepers and buoyancy modules initiated these buckles at pre-determined locations. Smaller buckles were also observed at unplanned locations in the pipeline system. These pipelines terminate at subsea structures situated at the ends of the pipelines. In order to track the pipeline's long-term global movement; the end displacements at these structures were recorded as well.

During its operation, a pipeline system will be shut-down and re-started multiple times, thus creating a series of thermal cyclic loadings. In order to ascertain the long-term performance of the pipelines under such sustained thermal loading cycles, a Finite Element (FE) model is built using the pipeline data, seabed bathymetry and other environmental conditions. The FE model is calibrated using the recorded 2012 MBES survey in-service pipeline lateral buckling profiles. The calibrated FE model generates axial stress ranges at critical locations (buckle crown); these stress ranges are subsequently used to perform fatigue analyses. The estimated fatigue damage is used to forecast the pipelines' long-term fatigue performance, which will determine the future inspection and monitoring plans.

This paper presents an overview of the 2012 MBES Survey conducted on three of BP's operational pipelines as well as the subsequent FE and fatigue analyses performed to assess the long-term integrity within lateral buckles.