bluuebunny/crossref_metadata_2025 huggingface dataset:
Global and Local Iceberg Loads for an Arctic Floater
Authors: Jordaan Ian , Stuckey Paul , Liferov Pavel , Ralph Freeman
Published: June 2014

Analysis of loads from icebergs for an Arctic Floater has been performed. The determination of iceberg loads was guided by the ISO 19906 International Standard. Global and local loads on the hull, as well as mooring loads, were studied. To determine loads at the specified levels of exceedance, probabilistic methodology using Monte Carlo methods was used, taking into account the areal density of the ice features (for example the number of icebergs per 10,000 km2), and the probability distributions of the size and mass of the features, their added mass, their velocity, eccentricity of the collision, compliance of the structure, and the strength of the ice. The influence of surrounding sea ice on iceberg loads, as well as iceberg management including detection, towing and disconnection were analysed. Iceberg areal density was determined based on an analysis of available data, including information on the various forms, such as tabular or bergy bit. The strength of ice in collisions involving icebergs was modeled based on full scale crushing data from ship rams with multi-year ice. The pressure-area scale effects associated with ice-structure interaction were taken into account, considering also scatter in pressure measurements for a given contact area. Separate relationships for local and global loads were used. The analysis accounts for the Ekman current acting on an iceberg, together with wind and wave drift forces. Motions of the floating vessel and the icebergs in sea states were analyzed, accounting for the prevailing environmental conditions. Probabilities of collision along the length of the floater and in the vertical plane have been calculated using Monte Carlo methods. A variety of assumptions have been made: no ice management, management with and without disconnection, and the effect of sea ice on detectability and management is included.
Arctic Relay Communications, Data Exchange and Enhancement Protocol (ARCDEEP) Through-Ice High Data Rate Optical Communication System
Authors: Mooradian Greg , Richter Dean , Marttila E.J. , Saade Edward
Published: June 2014

The potential oil reserves in the Arctic are enormous. However, the inherent difficulty (and risk) of oil exploration and production in the Arctic is proving to be the most challenging region in the world. The challenge will be to establish the ability to collect a wide variety of information (e.g., environmental) from under the ice and then deliver that information to a command center for analysis and application in a short amount of time. The Arctic Relay Communications, Data Exchange and Enhancement Protocol (ARCDEEP) Optical Laser Communications (OLC) system will support the real-time exchange and exfiltration (exfil) of information collected under sea ice, enabling the networking and fusing of data from fixed distributed sensors and mobile platforms (e.g., both aircraft as well as mapping autonomous underwater vehicles (AUVs) under the water) and the aggregation of their data for enhanced analysis/interpretation. Therefore, ARCDEEP becomes an Arctic "information enabler" dramatically increasing Arctic situational awareness (e.g., tracking an oil spill under the ice, exfiltrating subsurface Arctic sensor data, etc.).
Small Unmanned Aircraft Systems (SUAS)
Authors: Ziska Matthew
Published: June 2014

SUAS are available to support a number of arctic missions. Applications are continually evolving as the technology is better understood but here are some of the missions applicable to the arctic today:Sea Ice Monitoring3 Dimensional Terrain Modeling and GIS data product developmentMaritime Border PatrolOil Spill DetectionOil Spill Damage AssessmentCommunications RelayInfrastructure inspection / integrityIncident MappingCoast Line MonitoringIce Breaking Support / MappingSearch and RescueWildlife MonitoringScience Data GatheringAsset Security
Use of Robotic Aircraft in the Oil and Gas Sector
Authors: Pearce Wilson
Published: June 2014

Introduction

Getting the right information, into the right hands, in a timely manner, is a crucial aspect of oil and gas exploration and production, especially in harsh conditions. Many of the survey and surveillance jobs, including geological exploration, critical infrastructure inspection, pipeline monitoring, ice condition study and wildlife and other forms of environmental surveys can be dull, dirty and dangerous. These are well suited to robotic aviation.

Information today is gleaned from a variety of sources such as installed monitors, terrestrial patrols, fixed and rotary wing aircraft and satellites. Managing the significant issues of cost, risk, safety, flexibility and responsiveness, let alone the disparate nature of the data sets received, is a daily challenge.

Effective use of robotic aviation has the potential to greatly improve the situation. A robotic aircraft system that incorporates the airframe, sensor package and data fusion plan is a powerful tool. The quality of the data that can be gathered quickly, and in both a proactive and/or reactive manner has to be seen to be believed. What is even more significant is the huge reduction in footprint in terms of cost, risk and in the requirements for space, fuel and personnel. For example, the fuel required for a fixed wing robotic aircraft is less than one litre per hour, carrying similar or better sensors than a helicopter or light plane.

ING Robotic Aviation developed its expertise with the Canadian Army in Afghanistan, and to this day retains a team deployed with the Royal Canadian Navy in the Indian Ocean. Experienced gleaned from military operations is already proving to be useful in the civil sphere, for example in conducting flare stack inspections for Irving Oil and wildlife counts that can be conducted accurately and unobtrusively.
Aerial Reconnaissance in Support of Arctic Drilling Operations: Requirements, Challenges and Potential Solutions
Authors: Garas Victor , Simms Andrew , Lennox Ted , Jonasson Bruce , Blunt Joshua , Kokkinis Ted
Published: June 2014

Acquisition of broad, detailed and real-time information about ice conditions in the vicinity of arctic offshore drilling sites is one substantial challenge that faces effective ice management operations supporting floating drilling operations. Reliable and objective characterization of ice conditions up drift of the ice management fleet is needed to appraise an ice management system's anticipated efficacy with sufficient lead time to suspend or adapt operations if conditions become challenging or trend towards becoming unmanageable. Remote sensing technologies have the potential for reducing labor intensity and personnel exposure while observing and characterizing the changing arctic environment.

In this paper, the need for acquiring detailed ice information in real time to evaluate ice-induced hazards on offshore facilities in the arctic is presented with specific focus on airborne methods of measuring sea ice thickness, which is one of the most important parameters in assessing ice-induced hazards. The paper then discusses in detail how some manned and unmanned aviation concepts could be viable options for delivering persistent operational reconnaissance. In addition, infrastructural, technological and regulatory challenges associated with using airborne reconnaissance for continuous ice characterization in offshore regions of the arctic are presented and discussed.
A Tactical Ice Management Simulation Methodology and Approach
Authors: Wright B. , McKenna R. , Browne R.
Published: June 2014

There are a number of models that have been developed to assess ice management effectiveness. Many of these models are relatively simple in terms of how they treat pack ice conditions and ice management vessel performance needs. The Chevron Arctic Center has recently developed a substantially more advanced ice management model, one that incorporates key factors such as the full spectrum of "difficult ice situations", ice management support aspects such as level ice, pressure ridge and rubble field fragmentation, and other constraining effects on ice management operations such as poor visibility, darkness and ice pressure events.

In this paper, the Chevron ice management modeling approach is described. Key aspects include how ice conditions and dynamics are treated, and how ice management vessel effectiveness is assessed. Sensitivities relating to the number and capability of different ice management vessels are also noted. This method is probabilistically based and allows the user to assess the risk of "ice management failures" in relation to platform station-keeping limits, the ice management support system and the ice environment being considered. Several representative examples of this analysis approach are given.
Requirements on Logistics to Tow Large Gravity-Based Structures to the Chukchi and Beaufort Sea
Authors: Wernli Markus , FitzGerald Ken L. , Hjorteset Kare , LaNier Michael W.
Published: June 2014

Oil companies are considering large Gravity-Based Structures (GBS) as a potential solution to support operations in new offshore oil and gas field developments in the Arctic seas that are designed for year-round production in potentially 100-meter-deep waters. These structures support multibillion-dollar drilling, production, and storage facilities that are typically commissioned with topsides and consumables before entering the Arctic, and are towed with these elements already installed on the GBS to the installation site. However, the tow not only presents a high risk during the installation phase of the platform, but also has a significant influence on the design and cost of the GBS. Movement of these large offshore structures through the Bering Straits and into position at the installation location includes unique risks that result from the minimal precedence of these tows and the scarcity of local support and contingency ports. This situation suggest that typical approaches to risk identification, design criteria development, and application of risk mitigation approaches may merit reevaluation. This paper will discuss the logistics related to the movement of these large structures and discuss the various cost- and schedule-related risks that have to be identified to support the early design phases of the GBS.
Results Using Azipod Propulsion in Ice Management Operations
Authors: Hanninen Samuli , Heideman Torsten , Toivanen Olli
Published: June 2014

A major part of world's oil and gas reserves are located in Arctic and Subarctic seas, such as Sakhalin fields in Okthosk Sea as well in Chuchki Sea, Beaufort Sea Alaska. Year around operations in these areas results increasing need for special designed icebreaking offshore support vessels and tankers. Important characteristic of these vessels is the capability in ice managent duties.

Azimuth thruster offers great flexibility in different ice management using the thruster wake and propeller close contact with ice. Electric propulsion with Azipod propulsors has been used in such vessels with good success for many years and the system itself has shown to be reliable and very good characteristics when operated in ice. In Sakhalin region there has accumulated experience from 7 icebreaking vessels with ABB electric propulsion many equipped with Azipods. Recently two new icebreaking vessels with Azipod have been built for Arkutun-Dagi field. Electric Azipod propulsion system have been playing an important part in several arctic ship projects making the demanding projects technically and economically feasible. In this paper will be presented characteristics as well some full-scle test results where Azipod units are used in ice management type operations.
Performance Evaluation of a Multiphase Electric Submersible Pump
Authors: Morrison G. , Pirouspanah S. , Kirland K. , Scott S.L. , Barrios L.J.
Published: June 2014

Electrical Submersible Pumps (ESP) are widely used in upstream oil production. Pumps with the ability to operate with fluid streams that include gas are increasing. To better understand the ESP pump's behavior in these multiphase flow situations, Split Vane Impeller Pump (SVIP) designed for multiphase flow has been studied experimentally to determine the pump's performance in different operating conditions. The SVIP is a multi-vane electrical submersible pump which has been designed to increase the gas handling capacity of typical multiphase ESPs up to 70% gas volume fraction. Homogenized flow and finer bubbles produced by the SVIP pump helps the ESP to delay the surging and gas lock condition until higher gas volume fractions occur. The goal is to operate effectively at high GVF. In this work, an experimental study on the performance of a 3-stage SVIP is performed. Overall pump performance for different operating conditions are investigated for different inlet pressure, inlet gas volume fraction, water flow rate and rotation speeds using a mixture of water and air.
Development and Possible Applications of Mebo200 for Geotechnical Investigations for the Underwater Mining
Authors: Spagnoli G. , Freudenthal T. , Strasser M. , Weixler L.
Published: June 2014

Deepsea mining sites are usually large areas of polymetallic nodules or seafloor massive sulfide (SMS) deposits. Prior to underwater mining campaigns, successful exploration programs have to be taken into account in order to include selection of target areas by means of seafloor and sub-seafloor surveys of the rocks and sediments. Coring of the submarine sediments plays a major role for evaluating of the marine sediments and they are useful for future mining operations. The main geology which hosts the polymetallic nodules is pelagic clay. On the seafloor and specifically at the mudline, this kind of soils has very low undrained shear strength up to 20 kPa. In order to properly design the nodule harvester, which will be in contact with the sea floor, physical properties of the seabed and shallow subsurface (i.e. the upper 100–200m)are needed to compute bearing capacity. Underwater soil cores can be used to evaluate soil type, cohesion, unit weight of soil, modulus of elasticity. Seafloor massive sulfide (SMS) deposits are very different from the polymetallic nodules. In this case, cores are needed in order to assess possible anomalies. Measured uniaxial compressive strength (UCS) values strengths in the SMS zone can be very high. Drill cores are required for assessing the mineral content at these deposits. The MeBo200 is a sea bed drill rig presently developed by the MARUM Center for Marine Environmental Sciences at the University of Bremen and the department of Maritime Technologies of BAUER Maschinen GmbH. It is well suited for core drilling in formations of comparable strength and therefore it is suitable preparatory geotechnical exploration. MeBo200 is the second generation of MeBo. From 2008 to 2012 MeBo was employed in 9 expeditions. 66 deployments took place in up to 2,050 m water depth. 1,445 m were cored in different type of geologies, concentrating more on the quality of the cores. These include crystalline rocks from the Porcupine Bank west of Ireland, as well as very soft homogenous silty clays in the Gela Basin with very low undrained shear strength values. The recovery rate was good for hard rocks and cohesive soft sediments. Taking into account the case histories of MeBo it is possible to state that for underwater mining applications the new MeBo200 can be utilized for geological and geotechnical drilling campaigns.
Gap analysis for the development of a Geohazard Monitoring and Warning System
Authors: Cauquil Eric
Published: June 2014

The classical approach to cope with geohazards is to conduct a "baseline" geohazard assessment recognizing the threat (shallow gas, shallow water flow, gas hydrate, unconsolidated / over consolidated sediments, slope instabilities, over steepening seafloor (fault through, pockmarks…), active faults, mud volcanoes, seabed fluid escapes, chemosynthetic communities…) and to avoid it by moving the facility outside the impact area of the given geohazard. Avoidance is the safest and most satisfactory long-term solution to cope with geohazards. However, as E&P activity is moving to more complex and deeper geo-environmental contexts, recent projects have shown that it may not be possible to avoid the geohazard and its impact area. In this case, mitigation measures as reducing risk through engineering work may be implemented so that the risk is reduced to an acceptable level. In addition to the "baseline" approach, it may be necessary to evaluate the impact of a given geohazard that may evolve during the field life time (20–25 years). This new concern introduces the notion of time that is rather difficult to address for geological processes. For example, an area may be recognized as a sliding prone area and appropriate mitigation in terms of foundation design may be proposed during the engineering study, but the long term behavior of the sliding area must be properly evaluated and monitored for forecasting during the field lifetime. Similarly, seabed conditions and foundation bearing capacity may be subject to modifications during the life time of a field due to E&P itself, as subsidence due to reservoir depletion or overpressure due to gas/water/cutting reinjection.
Pre-FEED decision making for mooring system configuration using Progressive Reliability Method
Authors: Mousavi Mir Emad , Haverty Kevin
Published: June 2014

The safety of an offshore structure is significantly affected by the decisions made early in the Pre-FEED and FEED stages; however, a quantitative measure to evaluate the effect of each decision on system safety is usually not available. Mooring systems are particularly vulnerable offshore structures to such early decisions because they are exposed to uncertain extreme environments and already have a relatively high rate of failure in their components. This paper presents a Pre-FEED quantitative reliability analysis for the configuration selection of a mooring system, accounting for the uncertainties associated with the environmental loads and component strengths. By estimating the annual probability of failure of alternative mooring configurations, using Progressive Reliability Method (PRM) and some simplifying assumptions, the additional safety versus additional cost of different mooring configurations compared to the based configuration are compared and discussed. In the analysis of this study, the redundancy of the mooring system is considered by defining the system failure as if two or more mooring lines fail. The environmental conditions and the mooring component capacity variations are selected based on Gulf of Mexico projects. By estimating the response of the mooring system based on limited dynamic analysis for various return periods and loading directions, a regression model is used to develop the probability distribution of the conditional probabilities of failure under each return period and estimate the annual probability of failure of the mooring system. This simplified method decouples the environmental demand probabilistic analysis from the component demand and capacity probability distributions and therefore uses a practical probabilistic model to compute the safety of alternative mooring configurations. The results are useful for identifying the safest alternative configuration as well as quantifying the effect of adding more lines to the system or risk of each configuration. This study discusses the strength failure of the mooring components under extreme loads and other failure modes are beyond the scope of this work.
Evaluation Of A Composite Device With An Embedded Non-Intrusive Water Cut Sensing Platform For Production Tubing And Well Completions
Authors: Parker Alan , Edward Giles , Ladwa Ramesh M
Published: June 2014

We present the development of a unique water-cut/component meter with sensor elements embedded in a composite thermoplastic pipe. It is suitable for use in a high pressure, high temperature, and / or sour service environment. Composite construction allows the sensor elements to lie outside the flow path, without flow obstruction or contact with the flow-line fluids, and the sensing is capable of measuring the full flow line diameter without the need for active mixing, or vertical orientation of the meter. The sensing systems are low power, robust and are designed for zero planned intervention during a multi-year life. The sensor device is monolithic and suitable for high hydrostatic and flow line pressure and applicable for production tubing and well completions. The meter design is embodied in an number of patent applications.
MS New Dead-Crude Oil Asphaltene Inhibitor Test Method
Authors: Jennings David W. , Cable Robert , Leonard Geoffrey
Published: June 2014

Asphaltene deposition is a serious problem for deepwater subsea production systems. The potential for immense production losses coupled with the difficulties and expense in remediating deposition in subsea systems make it imperative that deepwater fields are evaluated for asphaltene concerns. If concerns exist, effective prevention treatments must be designed and employed. Therefore, having effective asphaltene inhibitors and correspondingly, better methods to evaluate inhibitor performance is extremely valuable for deepwater operators.

This paper discusses a new dead-oil asphaltene stability analysis method which has shown to be effective in comparing asphaltene inhibitor performance. The method can also be used in field monitor programs. Although not a live-fluid deposition test, the method offers advantages over some currently used methods, like ASTM D7601-04. The method uses an analytical centrifuge to evaluate the stability of asphaltenes in crude oils which have been simultaneously subjected to a solvent that destabilizes asphaltenes and centrifugal force. In comparison to ASTM D7601-04, use of the new method provides a better measure of asphaltene inhibitor effectiveness in crude oils due to:the application of centrifugal force andthe ability to perform testing with higher crude oil concentrations / less destabilizing solvent. Note, ASTM D7601–04 uses more than 97 % destabilizing solvent.

Its maximum recommended crude oil concentration is 2.67 %. The new asphaltene stability analysis method has been run at crude oil concentrations from 5 – 40 volume %.

The ability to perform testing with less destabilizing solvent is particularly significant as only a fraction of the total asphaltenes deposit during production. In field conditions, only the more "insoluble" asphaltenes precipitate and deposit. By reducing the destabilized asphaltene fraction to only the more insoluble species, dead-crude oil test method conditions can be moved closer towards field conditions. The amount of asphaltenes destabilized can be altered with the choice of destabilizing solvent and amount of destabilizing solvent used. This is the approach used in the new test method. Also, by using significantly higher crude oil concentrations in the method, more destabilized asphaltenes can be generated during the test despite reducing the fraction of asphaltenes destabilized. By increasing the amount of destabilized asphaltenes, more stringent asphaltene inhibitor conditions are created in the testing since asphaltene agglomeration occurs more easily in higher-concentration environments. Further increasingly stringent conditions are created with the simultaneous application of the centrifugal force. It has been found that these more stringent conditions allow better differentiation in evaluating asphaltene inhibitor performance.

This paper shows results from the new Asphaltene-Analytical Centrifuge Stability Analysis (Asphaltene-ACSA) method with different crude oils, destabilizing solvents, and asphaltene inhibitors.
Saudi Arabia's Manifa Giant Offshore Field Development: The Role of Technology
Authors: Arukhe James , Hanbzazah Shadi , Ahmari Abdulrahman , Al Ghamdi Saleh , Yateem Karam , Aramco Saudi , Bal Moustapha , Ahmed Danish , Baez Fernando
Published: June 2014

Field development costs have risen with oil price. A resulting challenge with Arab heavy oil development remains how to generate competitive advantages through deploying efficient technological innovations and making cost-effective solutions a crucial part of a firm's strategy for rigless interventions. With strict commitments to environmental protection, the need for operational excellence and several process improvements necessary to yield dividends in the form of safe project delivery and to overcome several technical difficulties is vital.

The scope of the paper is to examine coiled tubing (CT) stimulation and logging technologies used in the timely project execution of one of Saudi Arabia's largest field developments to cost effectively enhance matrix stimulation success. Some of these solutions include technologies for CT reach, CT access for dual laterals, acid placement optimization, and treatment effectiveness monitoring. CT extended reach solutions comprised tapered CT strings designed for ultradeep wells, drag reducers, tractors, and vibrators. Technologies for CT access for dual laterals include a flow activated multilateral tool for CT matrix stimulation employing pressure variation telemetry with bottom hole pressure (BHP) and casing collar locator / gamma ray (CCL/GR) for high success lateral identification.

To optimize acid placements, distributed temperature survey and pressure measurements are used to enhance diversion and acid placements. A blend of tools assisted to monitor, analyze, and adjust in real-time the reservoir and stimulation fluids interaction. Viscoelastic diverting acid is designed to viscosify in situ as the fluid spends on the reacted formation for chemical diversion in carbonates. The concentration of the diverter was optimized from 20% HCl to 15% HCl. A unique solution for monitoring treatment effectiveness evolved to include real time production logging using single strings for CT stimulation and real time profiling instead of memory logging. This solution required less equipment mobilization and no wireline unit. Intervention from 99 producers and injectors reveals operational and cost benefits from deploying technological solutions and justifies the degree to which each technology solution fits the overall field development strategy.

The implications of deploying these solutions include reduction of well counts from the original estimates in this field development to offer manageable total field development costs.
A Drill Stem Well Testing Design for Extreme HP/HT Exploration Wells: Strong design along with good operating and contingency procedures are essential to achieve safe and efficient DST operations.
Authors: Milenkovic Frederic , Zarina Nik
Published: June 2014

Design of Extreme/Ultra (E/U) HPHT well testing, from an operator standpoint, is a difficult exercise that involves long and meticulous preparation phases, where a large proportion of the work is devoted to dealing with contingency procedures. The first step consists of the evaluation of the complexity of the project since it drives the level of preparation, level of risks, support /expertise requirements and their financial impacts. The Value Of Information must be accurately justified since HPHT well testing involves tremendous costs. The second step is to understand what it takes to deliver an E/U-HPHT in a safe and efficient manner, meeting well testing objectives. Basis of design and procedures are developed without overlooking the importance of tubing stress analysis, design reviews, quality insurance, and laboratory tests (qualification or verification). The proper well construction and its integrity is of paramount importance in the success of well testing operations since it provides the operating envelope DST tools are relying on. This envelope will be highly stressed during all DST load cases and therefore all DST components installed are designed to accommodate these stresses safely. The uncertainties of actual Pore Pressure, Temperature (down-hole and surface) and reservoir fluids make the exercise even more complicated, therefore, implying a great deal of preparations and contingencies need to be in place. The importance of selecting the right annulus fluid increases the chance of a successful operation and thus under balance versus over balance testing philosophy must be thoroughly evaluated to resolve the dilemma of well control versus DST tools operability. All this steps must be taken after a thorough review of what the current technology can offer along with the understanding of its limitation. Over the last few years, services companies noticeably pushed to develop extreme tools in order to provide viable technical solution to complex Ultra HP-HT well testing. Nevertheless, recovering the DST string is known as being one of the upmost challenge in HPHT well testing, meaning the design of the production string (including a tubing free strategy) must be planned well in advanced. No string back to surface means no down-hole data & samples, therefore missed objectives and waste of money.

This paper describes a design approach and preparation for an EU-HPHT well testing on an exploration well being the first to be implemented by PCSB.
Innovative Solutions Make China's First Marginal Subsea tie Back oil Field into Production
Authors: Jiayou Mao , Jianjun Yang , Qingdong Yuan , Yiyong Liu , Zuan Yue
Published: June 2014

Liuhua4–1 oil field is located 215km to the south east of Hongkong in the South China Sea. The reserve was first discovered in 1987. Due to economical and technical challenges, it was not until 2012 the development of this field become reality. The 300m water depth oil field was successfully tied back to an existing oil field Liuhua11–1 oil field through subsea pipeline, power cable and multiplex control umbilical. The project executions include disconnection, life extension and re-hook up to the existing oil field FPS. It was also China's first tie back subsea development project. In order to develop this marginal oil field, a number of technical challenges were overcome through a series of new technologies successful development and implementation.
Qualification of Flexible Flowlines: Lateral Instability Testing
Authors: Tanaka R.L. , Morini R.G. , Godinho C.A. , Swanek D. , Timms C.
Published: June 2014

The need for oil exploitation in ever increasing depths drives the development of structures suitable to resist very high loads. In this context, the qualification process for flexible flowlines involves physical testing to demonstrate suitable performance for the intended application and to obtain data to improve the applied design tools.

As part of the qualification process, lateral instability under external pressure and cyclic bending, known as lateral buckling (LB), was investigated for a 6-inch ID flexible pipe flowline with wet annulus conditions. This was done by performing reduced-scale prototype testing in a hyperbaric chamber with the application of cyclic bending and external pressure. The external pressure was adjusted to the application depth of the particular flexible pipe, in an attempt to replicate the typical conditions of a Deep Immersion Performance (DIP) Test. The benefit of DIP testing is that it realistically replicates the loading conditions that the flexible pipe will be subjected to during installation or operation. However, DIP tests are very expensive, whereas reduced-scale testing can be performed at much lower costs. A concern of reduced-scale testing is if these tests can duplicate the loading conditions of the DIP tests.

This paper will describe the testing program, results and its relation to the design methodology.
Development of 4,000 m Class CFRP Drilling Riser
Authors: Miyazaki Eigo , Kyo Masanori , Seki Hitoshi , Takasaki Hideto
Published: June 2014

Japan Agency for Marine-Earth Science and Technology (JAMSTEC) is operating a deep sea scientific drilling vessel " CHIKYU" (Figure 1) to promote research on the earth sciences. 21st Century Mohole is one of the most challenging projects among current science proposals for the next decade. In this project it is proposed to penetrate oceanic crust, drill into the uppermost mantle across the Mohorovicic discontinuity and to obtain samples of mantle directly.

In order to accomplish this objective, it is required to drill about 7,000m below deep sea floor which water depth is over 4,000m. One of the elements which have a great influence on the realization of this target is a deep water riser. Generally, the material of a riser is high tensile steel. However, it will be very difficult to apply the steel riser to a drilling operation in the locations of more than 4,000m water depth due to the limitation of the strength. Therefore, JAMSTEC started to study a new material riser. CFRP (Carbon Fiber Reinforced Plastic) was selected as the primary candidate for the new material. It is classified by its raw material to two types, pitch-based carbon fiber (Pitch-CF) and PAN-based carbon fiber (PAN-CF). Pitch-CF has higher modulus of longitudinal elasticity and it will be more favorable for the dynamics of the riser. In this paper, outline on the developments of pitch-based CFRP riser are presented.
Inferred Depositional History of Middle-Late Quaternary Depositional Systems using Seismic Facies Analysis and Age Dating
Authors: Oyedele O.A. , Dupre' W.R.
Published: June 2014

The study area is located within the Mad Dog Development Area in the Gulf of Mexico. Several studies have been carried out in the area including the use of coherence and seismic amplitudes to identify fan sands behind the prominent Sigsbee Escarpment. This paper focuses on integrating seismic attributes and age dates to infer the depositional history of key deposystems landward of the Escarpment. The assessment was achieved by using data sets donated to the University of Houston by BP America, Inc.

The detailed architectural and facies analysis of the deposystems were interpreted using 3D high resolution seismic imaging and seismic attribution. Integration of the seismic facies analysis with biostratigraphic ages was used to infer the prevalent geologic processes and thus the depositional history of the systems. Deposystems identified in this study include a channel-lobe complex, channel/glide-track features, and mass transport complexes (MTCs).

The study revealed that the mapped depositional elements were mainly controlled by the interaction of sea level changes, sedimentation, and salt movement. Analysis of the channel-lobe complex and MTCs reveal successive periods of deposition which suggest periods of high sediment supply. Age dates of bounding markers reveal that these periods coincide with low stand to rising sea level. The influence of salt movement is not discussed in this paper though it was inferred from the study.
Obsolescence Management Through Technology Qualification Processes
Authors: Strouse J. M. , Sutherland J. , Botto A.
Published: June 2014

Technology in the oil and gas industry is continually changing and evolving to support demands on challenging and harsh operational environments. Understanding and working with any technology has inherent risks and benefits. The development of a technology qualification process (TQP) is crucial to ensure that established methodologies for qualification and management are in place.

As technology evolves, a common industry challenge is management of obsolescence on system and subsystems, especially newly designed or emerging technologies in components. Using TQPs to assess the potential challenges of obsolescence and the progression of changes as it develops helps minimize the risks and ensure the availability of equipment. This paper will develop a series of case studies that examine the use of integrity & obsolescence management through TQPs, thus, reducing or even circumventing the high risks involved with aging and developing technologies. The first phase of the paper will compare like industries by looking into the aging and developing sectors of the nuclear industry. It will assess the processes used at aging US nuclear reactors and compare methods used to develop and manage technology in the subsea industry. The second phase will be a case study that delves into TQPs and obsolescence management of hardware in subsea control systems. This section will look at a particular set of failure modes found during operation of subsea control systems and valves, identify how to manage these changes as the product develops, and what TQPs could be used to help eliminate failures going forward. The final element of this paper will look at processes and management tools that can be used as best practices going forward and provide insight into methodologies that will best serve developing technologies for the subsea industry.
Investigation of Next Generation Subsea Power Distribution System Architectures
Authors: Duan Yao , Forrest William , Li Xin , Bjørn Ulvestad Harald
Published: June 2014

Subsea power is the enabling technology for subsea processing to be implemented in more challenging applications. The current point-to-point power distribution systems are not sufficient to meet the increasing demands of future subsea processing developments. The development of a robust and high capacity subsea power grid is the technological first priority to achieve future subsea processing applications.

Four power system architectures, which meet the future needs of field developments, have been modeled and simulated in EMTP-ATP under both normal and fault conditions. The major contribution is that this study identified the system characteristics and the functional requirements of the major subsea and topside power components for the future subsea power grid. Comparing to the present point-to-point connection, additional power and control equipment necessary for the subsea power grid have been proposed. The conclusion is that having a more complicated subsea power system is necessary and feasible but there are a number of technical challenges to overcome, which requires close collaboration of field operators, system integrators, and equipment suppliers.
DFA Connectivity Advisor: A New Workflow to Use Measured and Modeled Fluid Gradients for Analysis of Reservoir Connectivity
Authors: Mishra Vinay K. , Cañas Jesus A. , Betancourt Soraya S. , Dumont Hadrien , Chen Li , De Santo Ilaria , Pfeiffer Thomas , Achourov Vladislav , Hingoo Nivash , Zuo Julian Y. , Mullins Oliver C.
Published: June 2014

In deepwater and other high-cost environments, reservoir compartmentalization has proven to be a vexing, persistent problem that mandates new approaches for reservoir analysis. In particular, methods involving reservoir fluids can often identify compartments; however, it is far more desirable to identify reservoir connectivity. Downhole fluid analysis (DFA) has enabled cost-effective measurement of compositional gradients of reservoir fluids both vertically and laterally. Modeling of dissolved gas-liquid gradients is readily accomplished using a cubic equation of state (EOS). Modeling of dissolved solid (asphaltenes)-liquid gradients can be achieved using the newly developed Flory-Huggins-Zuo equation of state (FHZ EOS) with its reliance on the nanocolloidal description of asphaltenes within the Yen-Mullins model. The combination of new technology (DFA) and new science (FHZ EOS) provides a powerful means to address reservoir connectivity. It has previously been established that the process of equilibration of reservoir fluids generally requires good reservoir connectivity. Consequently, measured and modeled fluid equilibration is an excellent indicator of reservoir connectivity. However, some reservoir fluid processes are faster than equilibration rates of reservoir fluids. The often slow rate of fluid equilibration makes it a suitable indicator of connectivity. Consequently, measurement of disequilibrium can still be consistent with reservoir connectivity. Moreover, the two fluid gradients, dissolved gas-liquid versus dissolved solid-liquid can be separately responsive to different fluid processes, thereby complicating understanding. A workflow is developed, the DFA reservoir connectivity advisor, to enable interpretation of the implications of measured fluid gradients specifically with regard to reservoir connectivity. Reservoir connectivity is difficult to establish in any event; analyses of fluid gradients can be placed in a context of the probability of connectivity, thereby significantly improving risk management.
Middle East India Deepwater Pipeline (MEIDP) crossing of the Indus Fan
Authors: Nash Ian , Burnett Christopher , Smith Russell
Published: June 2014

The Middle East to India Pipeline (MEIDP) will provide an economic and secure source of gas for India, where the demand for energy will continue to increase over the coming decades. The proposed pipeline will be the deepest major infrastructure pipeline laid with water depths exceeding 3000m for significant sections of the 1200km route. In addition to its depth the MEIDP will have to contend with significant potential geohazards, namely the Indian and Omani continental slopes, the Indus Fan, the Owen Fracture zone and the Qalhat Seamount. Since the Mid 90's when the Oman India Pipeline (OIP) was first envisaged the crossing of the Indus Fan has been held up as one of the major technical challenges for such a deep pipeline.

This paper will give details of the 2013 geophysical reconnaissance survey along the MEIDP route, with particular focus on block reconnaissance performed for the area where the route crosses the Indus Fan which is characterized by two topographical main structures: The channel/levee systems of the Indus fan which dominate the central part of the survey area; and the deep sea basins in the easterly and westerly sections. The channel/levee system is characterized by central channels with a series of adjacent terraces and numerous abandoned channel loops, which are partially refilled by the overspill sediments from active canyon areas. The pipeline route crosses five turbidity current channels with side walls up to 200m high, in water depths between 2100m – 3200m. With the exception of Channel 1 the channels follow a meandering flow pattern with general N-S direction. Channel side slopes up to 25° have been detected. Channel 1 on the western edge of the block follows a meandering E-W direction.

The results of the survey will be discussed together with details of the geohazard design process required to identify a feasible route across the Indus Fan and necessary intervention works at this feature to bring this project closer to reality.
Hydrogen Embrittlement Susceptibility of Precipitation Strengthened Ni-base Superalloys
Authors: Kernion Samuel J. , Magee John H. , Werley Thomas N. , Maxwell Paul
Published: June 2014

This paper discusses the results of an on-going investigation to rank the hydrogen embrittlement susceptibility of precipitation strengthened Ni-based superalloys using a rising step load (RSL) technique in four-point bending. Alloys characterized include UNS N07716, UNS N09925, and UNS N07718 heat treated to various strength conditions. Hydrogen was introduced either in-situ via an applied cathodic potential (external hydrogen) or prior to testing by thermally charging in gaseous hydrogen (internal hydrogen).

The RSL method measures the stress intensity required to cause propagation of a pre-existing flaw with and without the presence of hydrogen. Another method used to evaluate hydrogen embrittlement is the slow strain rate test, which characterizes material through the relative loss in ductility due to hydrogen exposure. While both methods provide a relevant measure of hydrogen embrittlement susceptibility, fracture mechanics testing such as the RSL method offers more useful information for the design of components.

Results indicate hydrogen embrittlement susceptibility is related to both the microstructure and the composition of the alloy. Measured fracture toughness values are also affected by the method of hydrogen exposure, however general trends among the materials are seen. In light of these results, the relative merits of the RSL testing method compared to slow strain rate testing is addressed, with a focus on overall applicability.

Failures attributed to hydrogen embrittlement of Ni-based superalloys in off-shore wells have emphasized the need to identify the limitations of these alloys in environments where the potential for hydrogen embrittlement exist.
Hydraulic Fracture Design for the Lower Tertiary Gulf of Mexico: Optimization Under Uncertainty
Authors: Podhoretz S. B. , Valkó P. P.
Published: June 2014

In this work we developed a methodology for making the strategic decisions regarding number and dimensions of hydraulic fractures for a high-cost, high-risk offshore vertical well in formations such as the Lower Tertiary Gulf of Mexico. Uncertainty is associated with the characteristics of the reservoir, the economics of the fracturing cost, and the fracture height growth. Reservoir uncertainty is manifested in the vertical permeability. Economic uncertainty exists in the total cost of the fracture treatment, which depends on the number of stages. Design uncertainty includes fracture height growth prescribed by a given aspect ratio. The method developed here is applicable to vertical wells with multiple, partially penetrating fractures in an anisotropic formation. The method applies the utility framework to account for financial risk. The optimization problem is represented as a two stage stochastic program with simple recourse.
Permanent Magnet Motor-Driven Pump Systems for Subsea Boosting in the Arctic Fields
Authors: Ganatra N.K. , Strikovski A. , Hollingsæter T.
Published: June 2014

In 2012, a unique combination of multiphase pump hydraulics and a 3.2 MW, 6, 000 rpm permanent magnet motor was qualified for subsea boosting applications. This new pump system delivers a versatile toolbox that can be deployed to fields in the Arctic and throughout the world. The qualification unit uses field-proven helico-axial hydraulics that are capable of boosting production fluids with gas volume fractions (GVF) as high as 100%. Further, the pump has been designed with modular construction, which allows the use of different types of hydraulics, viz. helico-axial, hybrid or single-phase, with the same qualified motor and auxiliary sub-systems.

The permanent magnet synchronous motor, integral to the qualified pump design, offers significant benefits over conventional induction motors. Combining the stiff, fully-contained rotor and the large rotor-stator "air" gap allows operating speeds up to 6, 000 rpm for the liquid-filled permanent magnet motor. In high GVF scenarios, the high speed operation allows differential pressures that are much higher than those generated with induction motors operating at 4, 000 rpm. The permanent magnet motor has the unique ability to provide the full load torque from zero speed, thus making it suitable to overcome some of the cold pump startup challenges of the Arctic. Sealed cable-wound stator and the rotor encasement in a carbon fiber sleeve permit the use of water-based barrier fluid, which is appropriate for the Arctic fields, where heightened environmental consciousness has added to the existing production challenges.

The barrier fluid pressurization system incorporates pressure control valves that operate purely on mechanical principles. This results in a stiff, fast-acting and reliable barrier fluid pressurization system that closely follows the pressure transients of the production fluid even in the long step-out distances of the Arctic. The successful qualification work includes permanent magnet motor startup and operation with long tiebacks, inclusive of step-up and step-down transformers, thus providing a system that is crucial to sub-ice power transmission.

Ongoing development of a new 6 MW, 6,000 rpm, 1, 034 bar (15, 000 psi) rated pump will better address some of the Arctic challenges by allowing the use of smaller pipe sizes, requiring the installation of one pump in place of two, simplifying subsea electrical power distribution and utilizing fewer mechanical interfaces. The 6 MW pump will provide high throughput capacity in high GVF applications combined with high pressure rise, thus resulting in longer tie-back and deeper water capabilities.