bluuebunny/crossref_metadata_2025 huggingface dataset:
Transforming Decommissioning Planning
Authors: Esson Roger
Published: April 2017

The decommissioning of offshore oil and gas infrastructure is a key aspect in the life cycle of the facility and incurs a significant amount of cost.

Decom North Sea was formed in 2010 with funding from the UK Department of Energy and Climate Change (DECC), Scottish Enterprise and Highlands & Islands Enterprise (HIE) to focus on developing a robust supply chain that could deliver decommissioning. Since that time the organisation has moved to being fully funded by its members and has grown to have a membership in excess of 400 from the UK, across Europe and internationally.

Only a small proportion of the UK Continental Shelf having been decommissioned, to date and current estimates predict expenditure to 2025 approaching £18bn (Oil & Gas UK Decommissioning Insights 2016).

Industry member's organisation Decom North Sea - in collaboration with the UK Oil & Gas Authority, development agency Scottish Enterprise and representatives from a cross section of its member companies - has developed a web-based information portal to capture tools which have proven to add value while promoting advocacy in capturing good practices and lessons learned from the execution of decommissioning projects.

Known as the Late Life Planning Portal (L2P2), the system was launched in 2016 and is likely to become the sole repository of information on the decommissioning of offshore oil and gas facilities, whilst helping to increase knowledge and learning for the industry and contribute to an overall increase in efficiency and reduction in the cost of decommissioning.
An Innovative Regional Approach to the Analysis of Hurricane Impact on Offshore Platforms
Authors: Dubois R. , Cuny J. , Kervella Y.
Published: April 2017

Hurricanes are one of the biggest threats to offshore platform integrity and personnel security in the Gulf of Mexico. In hurricane-dominated regions, history of extreme events at a determined location, like an offshore platform, are often too scarce for a direct Extreme Value Analysis (EVA). Extreme Value Analysis being essential for structural design, it is necessary to explore new methodologies.

The spatial method presented in this article is based on the Regional Frequency Analysis (RFA), adapted to hurricane-generated sea states. The goal is to increase the size of the sample of extreme events considered for a given location, to ensure a more reliable view of the distribution of very extreme events. For a concrete application, a hindcast dataset of significant wave height over the Gulf of Mexico is decomposed into homogeneous regions where distinct locations show similar hurricane impacts. The identification of these homogeneous regions is performed by applying the Ward hierarchical clustering method on peaks of significant wave heights generated by hurricanes.

Five homogeneous regions are identified and described. It is then possible to trade space for time: we thus build samples of extreme events for each of the homogeneous regions, hence gathering a larger number of events than if we had only considered hurricanes which traveled above one given location. A parametric distribution is then used to describe the distribution of extreme events inside each homogeneous region.

Extreme value analysis at a given location is then computed by transposing the corresponding regional distribution of extreme events. This methodology allows to reduce significantly the confidence interval width around the significant wave height extreme values estimate, especially for the 100 and 1000-year return values.

The methodology presented is quite an innovation as it had never been applied before to a dataset of sea states resulting from hurricane activity. The results are very valuable to obtain better estimate of potential extreme wave height due to hurricanes, hence increasing the confidence in offshore platforms structural design and the overall security. Moreover, this methodology can be applied to other regions of the world impacted by very extreme events, and to other kind of spatial data, such as winds, currents, or storm surge.
Case Study of a Customized Solution for Intervention Operations to Increase Well Production
Authors: Olstad Delaney Michael , Canny Steven A
Published: April 2017

Three wells on an aged platform required extensive intervention operations due to several downhole issues. This paper will review the life cycle of the project and focus on the efficiencies of the customized system which was used to increase production of the wells.

Due to several challenges and limitations associated with the platform, traditional methods were neither operationally practical nor financially viable. New technology in the form of a fit-for-purpose system was utilized to safely and effectively complete all necessary procedures. The system, which includes a pulling unit, provided the foundation to support multiple resources and offered a complete integrated solution. The modular design of the pulling unit and the efficient operational capabilities allowed for operations to be conducted within the parameters of the platform.

Because the platform was in 73 ft of water, the operator first considered using a rig for the operation, but eventually reconsidered based on overall project costs and space limitations. Furthermore, there were production operations ongoing which, if halted, would result in a financial loss. A rigless, crane-based program was not an option because extensive fishing was needed and required high pulling forces. When a casing hanger became stuck, the design of the pulling unit facilitated a seamless switch from supporting the downhole operations with the hydraulic mast to pulling with the integrated casing jacks. The ability to customize the pulling unit enabled safe and efficient operations to be completed and resulted in a 300% production level increase.

With platforms and wells have varying characteristics, the operational equipment spread needs to be customizable to each project's parameters and be able to provide a full range of services. This paper will cover how the pulling unit challenges the traditional methods of rigless intervention to provide cost-effective solutions that help to significantly reduce high operating costs.
Underwater Precast Reinforced Concrete Silo For Oil Drilling and Production Applications
Authors: Mahmoud Mostafa H
Published: April 2017

Proposed is a precast reinforced concrete multi-cell circular silo for deep underwater oil drilling and production applications. Drilling takes place from the bottom of the silo using modified land drilling equipment mounted on the silo foundation. The proposed silo evolved in response to the Deepwater Horizon oil spill which flowed for three months in 2010 in the Gulf of Mexico. On July 15, 2010, the leak was stopped by capping the gushing wellhead after it had released about 4.9 million barrels of crude oil. Provisional patent application No. 61366544 was filed on July 22, 2010. United States Patent No.: US 8,684,630 B2 was issued on April 1, 2014.

The silo is embedded an appropriate distance into the seabed to ensure: a) weight, ballast and buoyancy result in acceptable bearing into the seabed and b) lateral loads due to wind and water action on the silo are adequately transmitted to the seabed. If required, steel piles and/or steel anchors secured into the seabed are provided to supplement embedment.

The silo is constructed from multi cell precast concrete segments fabricated at a plant with access to water. The segments are transported one-by-one to final location and assembled vertically down segment-by-segment starting with the foundation followed by the wall. Construction does not require the use of a dry dock or scuba diving work.

The assembled silo has sufficient buoyancy to remain afloat throughout the offshore assembly process. Production of the precast segments is scheduled to permit completion of the silo between two hurricane seasons.

The blowout and spillage risks associated with the proposed silo are significantly lower than the blowout and spillage risks associated with current systems capable of drilling for oil and gas at such water depths. The oil leak containment capacity of the silo is an added advantage.
How Will Subsea Processing and Pumping Technologies Enable Future Deepwater Field Developments?
Authors: Kondapi Phaneendra. B. , Chin Y. Doreen , Srivastava Ashesh , Yang Zuying F.
Published: April 2017

This is a study on how subsea processing be the enabling technologies for future ultra-deepwater field developments and long distance tiebacks. This study identifies the gaps that need to be closed and decision making process during the field development life cycle by considering both the technical and economic constraints of various subsea processing technologies. As E&P companies continue to explore for oil & gas deeper and further into sea, the challenges associated with developing the deepwater fields are bound to escalate. Subsea processing technologies are the fastest growing technologies due to their huge potential to increase recoverable reserves and to accelerate production. It also enables for cost saving by moving some of the traditional topsides processing to seabed. As the reliability of subsea processing equipment is increasing, the industry is gaining more confidence in subsea processing. As industry gains more experience of design and operating subsea processing technologies, and closing the gaps, it improves understanding of the technology and making advancement to counter the challenges associated with harsher environments and complex fields. Properly-designed modularized compact subsea processing kits can be economic to deploy, and may potentially become an enabler for certain types of marginal field developments.

This paper addresses the challenges of reservoir characteristics and fluid properties, cost, risk, reliability, operability, installability, maintainability and intervention complexities; assesses the existing and emerging technologies; focuses on improving efficient compact design to reduce bulky and heavy equipment, achieving separation from heavy oil, and disposal of separated water. Certainly there are limitations in making the subsea processing viable and accessible to all operators but the technology needs and industry collaboration should overcome these challenges. Also there are opportunities for improvement and standardization, and modular design processing systems for reservoir suitability, field layout and topsides support.
Design Challenges for Power & All Electric Control Umbilicals
Authors: Dobson Alan , Deighton Alan
Published: April 2017

Since the first umbilicals were developed and installed to control and preserve subsea equipment they have continued to evolve to ensure effective operation in an increasingly challenging subsea environment. New material technologies, complex analysis tools and umbilical designs, such as in , have been developed to ensure umbilical systems operate through-out their service life irrespective of the ambient temperature, fatigue loading, hyperbaric pressure and tensile loads applied.

Typical Control and Chemical Injection Umbilical Arangement

 

The subsea industry needs to adapt to the challenge of reducing capital expenditure (CAPEX) costs due to reduced oil price. The potential cost savings could be realised through adapting the subsea processing system to treat processed fluids on the seabed together with utilising longer step out systems from existing facilities. This could drive a new step in umbilical evolution.

To support the potential evolution of subsea processing systems, the conventional control umbilical must evolve to incorporate the supply of electrical power and potentially electrical control to replace hydraulic control over long step out distances. This has a significant influence on the design of the umbilical system, introducing several new challenges which need to be addressed through material selection and advanced analysis techniques.

This paper will provide an overview of the potential evolution of the Next Generation All Electric umbilical and outline the design challenges and methods developed to maximise the reliability of the umbilical system.
Flow Assurance during Deepwater Gas Well Testing: Addressing Hydrate Associated Problems at Reduced Cost
Authors: Zhao Yang , Wang Zhiyuan , Zhang Jianbo , Pan Shaowei , Yu Jing , Sun Baojiang
Published: April 2017

Hydrate formation/blockage causes serious flow assurance issues during deepwater operations (e.g. well testing). Current dominant method is total prevention of hydrate formation with massive thermodynamics inhibitors (THIs), which render this method economically infeasible. Moreover, the required inhibitor storage and injection capacity may be far beyond the facility limits when the water production rate is high. In this work, aimed at addressing hydrate associated problems at reduced cost, a method is developed to prevent hydrate blockage with lower inhibitor consumption. Based on hydrate formation and deposition dynamics, a method is developed to prevent hydrate blockage during deepwater gas well testing. Implementation procedure of the proposed method is developed and further illustrated through case studies. We recommend that testing operations should be run within the Hydrate Blockage Free Window, HBFW. The HBFW refers to the period from the beginning of testing operations to the moment when a significant pressure drop increase is encountered. Case study work is conducted on a deepwater gas well in the South China Sea. The case study suggests that hydrate inhibitor can postpone the occurrence of conduit blockage. When the scheduled operation time (SOT) is shorter than the HBFW, the testing operation can be completed within the HBFW and no hydrate inhibitor is needed. If the SOT is longer than the HBFW, a small amount of inhibitor is required to extend the HBFW, thus the testing operation can be completed within the HBFW. The inhibitor consumption is much lower compared with the current over-inhibition method. With the proposed HBFW-based method, the inhibitor storage/injection capacity requirement can also be relaxed. The study suggests that with lower inhibitor consumption and inhibitor storage/injection capacity requirement, the HBFW-based method can address hydrate associated problems during deepwater gas well testing at reduced cost. In addition, the reduced inhibitor storage/injection capacity requirement makes this method more feasible especially when high water production is encountered during testing operations.
Experimental Investigation of Severe Slugging Control by Surfactant Injection
Authors: Barreto Carolina V. , Pimenta Amanda , Karami Hamidreza , Pereyra Eduardo , Sarica Cem
Published: April 2017

Recently, with the ever-increasing development of offshore fields, the use of long risers fed by lateral flow lines has significantly increased. This type of configuration exposes the production system to severe slugging, particularly with decline in reservoir pressure and consequently flow rates. Severe slugging can cause huge pressure fluctuations and may result in decreased recovery and separator flooding. This study is an experimental and theoretical effort to analyze how the application of surfactants can suppress or eliminate severe slugging.

The experimental study is performed in a 2-in ID facility, consisting of a 64-ft flow line with 1° downward inclination, followed by a 41-ft riser. Water and compressed air are the liquid and gas phases, and an anionic surfactant is applied continuously. First, effects of surfactant delivery location are investigated by injecting at three points, namely, riser base and flowline inlet without or with a static mixer, used as an external source of agitation. Pressure and holdup fluctuations with time, slugging frequency and surfactant efficiency are monitored. Moreover, a high-speed camera is used to monitor blowout stage and analyze gas front thickness and velocity. Pressure fluctuations and surfactant efficiency are experimentally investigated by changing the operating conditions. Tests include without and with surfactant at different liquid and gas flow rates.

Firstly, the experiments are conducted with lowest superficial gas velocity (vSg) and highest superficial liquid velocity (vSL) values. At these conditions, severe slugging is partially eliminated only with high surfactant concentration and the use of static mixer. The use of surfactant in other locations results in elimination of slug production stage and reduced cycle duration, but negligible changes in pressure profile. Then, a new test matrix is designed to conduct tests at higher vSg and lower vSL values, moving towards the boundary of Bøe's criterion for severe slugging. Under these conditions, severe slugging cycle durations and pressure fluctuations reduce and elimination efficiency of surfactant increases significantly. In addition, severe slugging severity and elimination efficiency are correlated with Boe's criterion coefficient.

This study is an attempt to characterize severe slugging magnitude based on operating conditions, and investigate surfactant efficiency for different delivery locations. Considering the limited number of studies on this subject, the results can provide an experimental and theoretical source to optimize surfactant application in production systems facing severe slugging.
Comparative Economic and Technical Evaluation of AG FGTL Floating Gas to Liquid Vessel vs. AG FLNG
Authors: Nguyen Xuan Chi , Mihaeye Komla , Shim Woolyong , Lee Charles
Published: April 2017

This study presents a comparative evaluation of a Floating Gas to Liquid Facility (FGTL) and a Floating Liquid Natural gas Facility (FLNG) as a way to monetize Associated Gas (AG) from existing oil producing offshore fields or from remote offshore gas fields. The study aims at showing that the FGTL is an option to be considered as a way to monetize AG.

For this purpose, a previous study presented to the OMAE under OMAE2016 – 55152 is used for the FLNG with one liquefaction train for nitrogen refrigerant. This FLNG concept serves as a benchmark to evaluate the technical and economic relevance of the FGTL through the Net Present Value (NPV) of the Life Cycle Cost (LCC). The LCC compares the difference between the FGTL and the FLNG NPVs on the basis of a selling price for the gasoline of 1.4, 2.0 and 2.4 USD/Gal with a price for the LNG varying from 3.5 to 7.5 USD/MMBTU.

The AG FGTL is presented in detail with a capacity of 6,000 bpd of gasoline (methanol production being an option to Gasoline). Natural gas is converted into gasoline by a proprietary natural gas to Liquids technology awarded with AIP (Approval In Principal) by ABS for off-shore GTL, which includes five principal steps in one continuous gas-phase process loop using only standard components: (1) Steam Methane Reforming; (2) Methanol Synthesis; (3) Gasoline Synthesis; (4) Gasoline Treatment; (5) Separation. This proprietary technology has several advantages over other GTL technologies including single product, long catalyst lifetime and higher allowable levels of CO2 in AG. Gasoline produced using a proprietary natural gas to Liquids technology can be blended with refinery gasoline or sold directly into the wholesale market.
Subsea Power JIP - As Enabler for All- Electric Subsea Production
Authors: Bugge J. Ø. , Ingebrigtsen S.
Published: April 2017

The journey towards the realization of the subsea factory is well on its way, promising the benefits of subsea processing and production. This "Grand Challenge" places extreme demands on the reliability, uptime and safety of the technology for distributing, delivery and control of the power system.

ABB Oil & Gas is running a Joint Industry project together with Statoil, Total and Chevron to develop technologies for subsea power transmission, distribution and conversion at greater distances, in deeper waters, and in harsher environments. The project started up in 2013 and is targeting a 3000-hour shallow-water system test in 2018, including the qualification of pressure tolerant medium voltage switchgear, medium voltage drives, as well as supporting controls and auxiliary supplies.

The project budget is in excess of 100 MUSD, funded by ABB, Statoil, Total, Chevron as well as The Research Council of Norway. The target environment is water depths up to 3000 meters, transmission distances up to 600 km, and power levels up to 100 MW.

The project follows the TRL development stages for technology qualification applied to components, sub-assemblies and equipment. This is a systematic approach ensuring that the technology will function reliably within specified limits, and it provides a common understanding and terminology of technology status and risk management. Qualification includes extensive testing of components subjected to test conditions derived from a common understanding of realistic component/equipment specific stresses throughout an agreed life-cycle mission profile, with particular emphasis on learning the behavior and limits of different designs. Comprehensive confirmation of the desired function as well as reliability testing is primarily conducted at the level of the component where a functional failure can be defined and accelerated conditions applied. Further, we perform sub-assembly testing mainly geared toward confirming the overall function, design margins, and the thermal and high-current performance. Formal qualification of key components and sub-assemblies is planned for 2017. Based on qualified components, final prototypes will be assembled in 2018 for a 3000 hour shallow-water endurance test and system demonstration.

The project passed a decision gate milestone in April 2015, having verified technology concepts as well as TRL2 for key components. Prototypes under development include full-scale subsea drives and switchgear with supporting controls and LV auxiliaries and functional verifications in key ABB factories. During 2016 key prototype designs have been tested and functionally demonstrated over a limited operating range. This paper provides a summary of the current status of the project highlighting the most critical areas for success, such as designing for modularity and the demanding reliability and availability targets, and utilizing the best experts and experience across ABB as well as the participating oil companies.
Euryale Moonpool – Innovative Naval Architecture Design Enables Full Dual Drilling Accessibility on a Drillship
Authors: Hendriks Sjoerd , Man Pieter de , Zijderveld Govert , Diemen C. van
Published: April 2017

The offshore drilling market is pushing for more cost efficiency, more efficient drilling packages and more safety and redundancy, but also have the desire to be able to drill and develop more complex wells in deeper water. New concepts and designs will be needed to meet these challenges and make drilling complex and deeper wells commercially attractive.

A rig design solution to provide increased drilling efficiency is to set up the rig for full dual drilling featuring two fully equivalent well centers. This will combine the benefits of dual activity with additional rig flexibility and redundancy. In the existing configurations well centers are mostly not equivalent, as for example with the commonly used main or auxiliary hoist, specific operations are be limited to only one well center. When aiming for full interchangeable well center functionality, at all times full accessibility to both well centers is required, at drill floor level as well as in the moonpool. This arrangement does not exist on earlier or contemporary drillship designs. In general a drillship features ample deck space, but the vessel deck areas and the well centers are longitudinally arranged. This causes the forward well center to block access from the forward deck area to the aft well center, and vice versa.

By breaking with traditional naval architectural thinking patterns, an innovative approach to the drilling process in a moonpool arrangement is introduced. It comprises a transversely oriented moonpool, named the Euryale moonpool concept. The Euryale concept allows the well centers to be transversely arranged, and thus providing the right accessibility to both well centers on the drill floor as well as in the moonpool from forward and aft deck areas, ensuring all advantages of full dual drilling and full redundancy on a drillship.

The (patent pending) Euryale moonpool features not only full dual drilling accessibility, it also mitigates sloshing motion in the moonpool during transit due to the significantly reduced length of the moonpool. The calm water in the moonpool not only creates a safer working environment for high value equipment and personnel, it saves fuel cost and reduces emissions as well. The Euryale moonpool is integrated in the ship's structure ensuring the overall integrity of the drillship, and does not contain any failure sensitive underwater mechanical parts nor protruding parts in the moonpool that might impose damage on the deployed riser.

A patent has been applied for the Euryale moonpool.
Response of Vertically Loaded Centrifuge Suction Caisson Models in Soft Clay
Authors: Wallace J. F. , Rutherford C. J.
Published: April 2017

Tidal current turbines are designed to interact with flowing water. This interaction results in a significant horizontal load and corresponding overturning moment that can be resisted through a compression and tension mechanism on opposing foundation legs if the foundations are configured as a multipod. This study investigates the response of suction caisson foundations in soft clay with an aspect ratio of one to this compression and tension loading by means of centrifuge testing.

Suction caisson models with an aspect ratio of one were fabricated out of T6-6160 aluminum at a scale of 1:90 and tested in kaolin testbeds. The kaolin testbeds were consolidated from slurry under an effective stress matching the effective stress at the mid depth of the testbed when spun at 90-g. A series of monotonic vertical load tests were conducted at 90-g on a beam centrifuge using a vertical stepper motor. The series of load tests comprised of undrained monotonic loading phases conducted both prior and post long period cyclic load phases corresponding to the longer period components of tidal current velocity fluctuations.

Geotechnical centrifuge testing allows for the investigation of suction caisson response under loading conditions applicable to tidal current turbine structures under realistic stress and stress distritbutions by artificially increasing the gravity. The response of the suction caisson under vertical monotonic loading without any prior cycling provided a baseline case for determination of the effects of long period cycling (i.e. semi-diurnal tidal current fluctuations) on future monotonic undrained loading. The load tests showed that the effects of long period cyclic loading on the degradation of the undrained monotonic capacity were dependent on the amplitude of the cyclic loading. The cyclic strain thresholds that caused a significant decrease in the post cyclic monotonic capacity were not the same for compression and uplift loading mechanisms. This indicates that serviceability constraints will play a critical role in tidal current turbine foundation design. Ensuring reliable foundation design will allow for cost efficiency during construction and over the lifetime of the tidal current turbine structure.

As tidal current turbine technology, at this time, is primarily in the prototyping stage, it is key to understand the response of the foundations to these loading conditions in order to increase the cost efficiency of the overall structure.
World-First All-Electric Subsea Well
Authors: Schwerdtfeger Thomas , Scott Bruce , Akker Jan van den
Published: April 2017

K5F3, the world's first fully all-electric well of the subsea industry, has been opened to production on 4 August 2016.

This paper will present the benefits of electric subsea control compared with current state-of-the-art hydraulics methods, describe R&D projects that led to this first industrial application, and outline the main project phases and milestones. Difficulties encountered will be presented, and lessons learned will be disclosed. Finally, this paper will present future plans for subsea electric control going forward.

The current state of the art for subsea well control is based on hydraulic technology. Hydraulic fluid is supplied from a host facility to the subsea wells through dedicated tubes within an umbilical and is distributed to the wells, in which the typical components are the manifold, Christmas tree valves, and downhole safety valve.

The all-electric subsea well consists of an electric subsea Christmas tree, electric downhole safety valve, and associated subsea control modules. Valve control is established via an electric cable.

The main driver for this innovation is cost reduction. Umbilicals are complex, difficult to install, and highly expensive. Replacing hydraulic fluid tubes by an electric cable within the umbilical can provide a 15% cost savings over a 30-km step-out. Implementing electric technology for Christmas tree valves and downhole safety valve control can also generate a further 10% cost reduction. All-electric subsea control is also an enabler for subsea processing innovations for more cost-effective subsea developments in a low oil price context. A global 30% to 40% reduction, outside of market effects, is the goal. This technology improves control of environmental impact by removing the risk of hydraulic fluid release, and personnel safety is improved with the removal of high pressure equipment and containment on topside facilities. Finally, electric technology demonstrates higher reliability compared to hydraulic systems and offers less complex subsea distribution and simpler hardware components.

Electric Christmas trees have been successfully operating on two wells of the K5 field offshore Netherlands since 2008, and the electric downhole safety valve has been developed. Although K5F3 is a subsea well in a shallow-water environment, all components have been qualified for 3,000 m of water. In 2015, the global control system has been fully qualified and successfully tested through factory acceptance testing (FAT), extended factory acceptance testing (e-FAT), and site integration testing (SIT). The well was spudded early 2016, completed in June, and successfully put on stream in August.

Electric control of wells is already taken into account for conceptual development studies and will become the base case for all of one operator's deep offshore projects when K5F3 demonstrates the efficiency of the technology.
GluBi® Pipe - A New Development of A Reelable Lined Pipe
Authors: Schueller Thomas , Hoffmann Reinhold , Banse Joachim , Lahmann Volker
Published: April 2017

For two decades the mechanically lined pipe has been applied as onshore and offshore pipeline in the oil and gas transportation. Up to now more than 1,000 kilometres of this kind of linepipes have been installed. In the past the main offshore installation methods for mechanically lined pipes were S-lay, J-lay or Bundle. The objective was to produce a reelable mechanically lined pipe with dimensions of 6 up to 18" without any further procedures such as application of internal pressure or reinforcements of the liner material. Over the last years, various approaches were investigated to prepare the mechanically lined pipe for the reeling technique which is much more efficient and economic than the above mentioned installation methods.

The manufacturing process of the new product is based on the process of the mechanically lined pipe called BuBi®. A CRA pipe is expanded inside a carbon steel pipe, using a hydroforming process. Between the two pipes a glue is coated to produce adhesion. The pipe ends are welded using a weld overlay method. The main development work was finding a solution of the welding at a glued pipe end. This was successfully done.

The result is a glued linepipe called GluBi® having the same weldability and processability properties as the well-known mechanically lined pipes and it is reelable without the risk of wrinkling. Furthermore the strength and corrosions resisting properties as well meet the requirements of the onshore and offshore oil and gas transportation. Currently the new product development is going through the DNV qualification DNV-RP-A203. The market launch is planned for 2017.

The main benefit of the new product, the glued mechanically lined pipe, is the cost saving factor. The reeling process can be faster because the pipe section does not have to be filled and pressurized with water. Another advantage is the lighter weight. The vessel is able to load more pipes. The glued mechanically lined pipe is a reasonable completion of the metallurgically clad pipe and the conventional mechanically lined pipe. It will find its place in the future of the oil and gas business.
Establishment of a Quantitative Risk-Based Approach for Evaluation of Containment Performance in the Context of Permanently Plugged and Abandoned Petroleum Wells
Authors: Arild Øystein , Lohne Hans Petter , Majoumerd Mohammad Mansouri , Ford Eric P. , Moeinikia Fatemeh
Published: April 2017

A large number of offshore oil and gas wells need to be plugged and abandoned on the Norwegian Continental Shelf in the coming decades, implying significant costs to the industry. To develop a methodology for evaluation of the quality of the barrier system of permanently plugged and abandoned wells from a risk perspective, the research project "Leakage risk assessment for plugged and abandoned oil and gas wells" has been initiated. The chosen quality measure to quantify containment risk in this context is the "leakage risk" expressed in terms of probability of barrier failure and potential future leakage rates.

Reviewed papers consist of fragmented contributions to a complete framework for leakage risk assessment of plugged and abandoned wells. However, they do not provide a complete risk assessment framework with a corresponding detailed analysis. Without such a framework, regulations will be limited to prescriptive approaches.

As an alternative to the currently prescriptive approach to plug and abandonment operation, this article presents how a risk-based approach can be used in practice by incorporating assessments of probability of leakage and the consequence (leakage rate), as well as uncertainty quantification. A comprehensive methodology and workflow, encompassing required steps for risk-based evaluation of containment performance, is established and presented in the paper. It is shown that this approach can provide a quality measure for a given plug and abandonment design and subsurface conditions.
Managing Missteps: Complications with Marine Magnetometer Surveys and Data Interpretation
Authors: Haddock Daniel A.
Published: April 2017

The objective of this paper is to outline the advantages of using a gradiometer over a marine magnetometer for surveying the seafloor. Marine surveys conducted with a gradiometer will minimize external interference in the field allowing the interpreter to provide quick results with confidence.

Many survey companies operating in the oil and gas industry rely heavily on a single magnetometer, which if not utilized properly can create multiple problems for archaeologists. Magnetic data with outside interference, bottom strikes, or collected during geomagnetic storms will creates data artifacts that look like real magnetic anomalies. Several shallow water surveys from 2015 are provided as examples of poorly collected data, which show how the data can inhibit an archaeologists' recommendations to operators. Operators that are required to use marine magnetometers will see the value in using gradiometers over single marine magnetometer, especially in surveys that may potentially identify shipwrecks or in areas with the potential for unexploded ordinance (UXO).

Poorly collected magnetometer data can increase interpretation costs and may require the area to be resurveyed there by delaying future projects. The adoption of the gradiometer over the magnetometer is recommended across the board for all operators. With the broad adoption of the gradiometer, archaeologists can provide better recommendations for future exploration and development to the oil and gas industry, which can prevent damage to cultural material, subsea structures, UXO and allow for a better collaboration with BOEM and BSEE.

Even though gradiometers have been in use for marine surveys for over 60 years (Wow, Cooper 1989), they are rarely used for marine surveys, especially in the well developed areas. This paper will show the results of poorly collected magnetometer data to demonstrate the need to adopt the gradiometer as the standard for marine magnetic surveys.
A Submarine Full of Mercury
Authors: Sparrevik P. M. , Eek E. , Klinkvort R. T. , Eiksund G. R.
Published: April 2017

This paper describes the geotechnical conditions and preparations for remediation work performed so far by the Norwegian Coastal Administration in order to protect the marine environment from the toxic legacy of U-864, a German submarine sunk by the British navy outside the west coast of Norway near the end of the Second World War. As the sloping seabed at the location of the wreck is unstable, the first step was to install a large counter fill to prevent sliding of the contaminated sediments.
NorMoor JIP, Structural Reliability Analysis for Mooring Lines in Ultimate and Accidental Limit State
Authors: Hørte Torfinn , Okkenhaug Siril , Paulshus Øivind
Published: April 2017

DNV GL is currently running a Joint Industry Project, "NorMoor JIP," with participants from oil companies, engineering companies, rig-owners, manufacturers and marine authorities. Our motivation for initiating a study on mooring line reliability started out with questions raised with regards to the applicability of the mooring standards. All the global standards (API, ISO, DNV, others) are mostly based on work from late 1990s, when frequency domain analysis was prevalent while time domain analysis is often applied today. The reliability level implied by these regulations is not known, and we also see that the mooring standards are interpreted and applied differently.

The objective of the NorMoor JIP has therefore been to provide a more consistent analysis methodology, and calibrated safety factors for time domain in line with this methodology. This is achieved through reliability-based calibration for a range of different units, mooring systems, water depths and geographical locations. Thus, the NorMoor JIP is intended for global application, and the aim is to get the results implemented into global standards like ISO.

Structural reliability analysis has been applied to calculate the probability of mooring line failure for intact mooring systems (ULS) and damaged mooring systems where one line is removed (ALS). The reliability analysis is based on a detailed probabilistic model of the metocean environment, state-of-the-art response analyses and strength data from break load tests. The probability of failure is calculated as a function of the magnitude of the safety factor. It is shown that present regulations result in a significant scatter in reliability level between the cases. An alternative design format with 2 partial safety factors may potentially reduce the scatter. Differences in results for hurricane conditions in the Gulf of Mexico and storm conditions on the Norwegian Continental Shelf are obtained, indicating the need for a different design philosophy for the two locations.

The present work provides a unique and comprehensive set of results, where advanced reliability methods are used in combination with detailed response calculations in the time domain. The results provide a basis for calibration of mooring design for ULS and ALS and subsequently for regulators to update their rules. Calibration of safety factors and selection of target reliability level are presented in a companion paper at OTC 2017.
Towards a Global Public-Private Protection Model
Authors: Faulk Kimberly L , Fucik Ken , Varmer Ole , Wachsmann Shelley
Published: April 2017

The offshore energy extraction industry, both renewables and oil and gas, continues to push into frontier areas where little to no protection exists for underwater cultural heritage (UCH) sites. Despite relatively rigorous regulatory requirements in the United States and the North Sea, other areas around the world have minimal to no cultural heritage regulatory frameworks to manage discovered archaeological sites.

Operators with experience in more mature fields often assume any archaeological discoveries will result either in additional regulatory pressure by the national or domestic government, or that the sites will be protected as a matter of course. Unfortunately, a patchwork of cultural heritage laws that imperfectly interface with offshore energy regulations can all too often result in no protection for these sites, meaning the sites are protected only by the silence that surrounds their discovery.

A new model, under development by partners from the energy industry and external cultural heritage experts, suggests a solution: a standalone database of discovered antiquity sites from energy extraction projects that would be voluntarily shared both with industry partners and government regulators. Operators would be able to access the database to help guide field decisions, and regulators would be able to use the information in their efforts to prevent looting and unauthorized salvage by third party salvage firms. The concept, while simplistic, requires industry and governmental consultation and cooperation.

This paper provides an overview of the solution, and calls for assistance from stakeholders to help solve a 21st century archaeological and industry problem - protecting the sites that lie deep beneath the surface, and that have survived for thousands of years - while allowing responsible energy development to continue.
Subsea Smart Crossing: An Innovative Solution to Simplify Field Architecture and Enable Cost Effective Installations of Subsea Pipelines for Long-Tie Backs, Scarp and Canyon Crossings, and Ultra-Deepwater Applications
Authors: Kalia Akshay , Pinho Adriano , Skowronek Tyler , O'Neill Eoghan , Mebarkia Sid , Critsinelis Antonio
Published: April 2017

Subsea pipelines play a significant role in E&P systems and are often called the lifelines of offshore oil and gas fields. These pipeline systems now cover greater areas and therefore traverse greater distances, go to deeper regions, and use larger-diameter pipelines. These developments present several challenges, including:

■ geohazards due to scarp or canyon crossings ■ multidiameter requirements ■ reduced-diameter risers to interface with large bore pipelines ■ ultra-deepwaters where top tensions become installation limitations ■ piggability of varying pipeline diameters, branching, and materials

Most current approaches for these new frontiers rely on stretching the current design and installation practices that involve pushing materials and equipment to their limits, which increases risks and leads to very expensive solutions (high capex and high opex) for developing, installing, maintaining, and operating subsea pipeline systems.

A subsea pipeline smart crossing system was developed to be a cost-effective solution that enables interconnectivity of different types and sizes of pipes to address the previously mentioned challenges and simplify subsea field architecture.

This paper presents the challenges and constraints for two different field architectures, outlines the subsea pipeline smart crossing solution, and presents its associated technical and commercial benefits that allow operators to optimize their spend on development, installation, and operation of subsea pipeline systems.
Profit Increase With New Subsea Boosting Products
Authors: Hofstad Åge , Nilsen Hans Christian
Published: April 2017

The oil and gas industry is continuously developing new technologies in answer to increasingly challenging demands. In the current market situation, where the oil price is dramatically reduced, these demands are strongly driven by finding the most cost efficient field development solutions. These solutions often call for stretching the requirements on subsea technologies. One solution that has been applied for years, with good track record, is the use of subsea boosting. Pressure on more efficient subsea boosting solutions has led to a number of development initiatives in the industry.

Aker Solutions has, together with a few main oil companies, developed a new multiphase pump technology which is soon ready for the market. This will expand the operation envelope for subsea boosting and create better opportunities for more effective offshore field development. A parallel, and equally important, development activity has been the development of a new large duty, 6 MW, subsea motor.

This paper will focus on the new 6 MW multiphase pump and motor developed and tested by Aker Solutions and its JIP partners. The step-wise applied development program will be reported, describing the main activities in the qualification of the new technology. Newly obtained results from the pump and motor qualification programs will be presented. Finally, an example will be presented on how this new boosting machine can be utilized to generate increased economic value for a subsea project.

The new pump and motor opens up for improved field economics with a greater ability than ever before to maximize profit by increasing the oil recovery and reduce the total production time by, in some cases, several years. This has demonstrated to provide considerably improved net present value since the oil production peaks out years earlier.
Design Verification and Load Estimation of Subsea Wellhead in HPHT Applications
Authors: Chang Gwo-Ang , Liu Meng-Lung , Song Hao
Published: April 2017

Subsea equipment design verification and validation are to be performed by analysis and testing, respectively. Two of the most important aspects of this process for high-pressure, high-temperature (HPHT) applications are load estimation and fatigue assessment. This paper presents dynamic loading scenarios typically considered in the design of subsea wellhead in HPHT applications during service life as well as load estimation of these scenarios, particularly on riser loads. Fatigue damage to the subsea wellhead is also included to examine the significance and effect of the loads from each of the loading scenarios.

Dynamic loading scenarios in drilling and production phases are evaluated in the paper. In the drilling phase, typical loading scenarios for the riser in connected conditions with wellhead are evaluated. A typical drilling system, generic sea state scatter diagram, soil condition and operational profile are selected to estimate the dynamic loads for each of the scenarios. In the production phase, typical loading scenarios are also evaluated. A typical subsea production system with the same sea and soil condition as drilling but with different operational profile is selected to estimate the dynamic loads for each of these scenarios.

A typical wellhead system including wellhead housing, conductor, and casing system is selected for the riser load estimation and the wellhead fatigue assessment using fracture mechanics method is carried out in accordance with API 17TR8.

Dynamic loads estimated from the scenarios in drilling and production phases are compared at the top of the wellhead in terms of maximum load and load histogram. The significance and effect of these loading scenarios are also evaluated from the fatigue standpoint at select hotspots on the wellhead system. From the study, it is observed that loading from drilling and production phases are equally important and both should be considered to verify the subsea wellhead's structural capability.

In the paper, an analysis procedure to evaluate the riser load to the wellhead and fatigue assessment of the wellhead is proposed, which may be used for the design verification of subsea wellhead in HPHT applications.