bluuebunny/crossref_metadata_2025 huggingface dataset:
Risk-Based Assessment of Scour Around Subsea Infrastructure
Authors: Tom Joe , Draper Scott , White David , O'Neill Michael
Published: April 2016

Scour poses a significant risk to infrastructure placed on mobile seabeds. Seabed mobility is common on the North West Shelf of Australia, in parts of the North Sea, and also occurs in the deepwater Gulf of Mexico, due to loop currents. Scour can undermine structures and, for shallow-skirted mudmat foundations, there can be significant consequences including excessive settlements, tilt and loss of bearing and sliding capacity. However, scour mitigation via engineered protection is costly, and to be avoided if possible.

This paper describes a new quantitative risk-based approach for assessing the susceptibility of subsea infrastructure to scour processes. This probabilistic scour assessment accommodates measurable uncertainties in metocean and seabed conditions, using new characterization techniques. The approach allows operators and owners to better assess the optimum strategy to address scour risk, selecting from mitigation during installation or in-service monitoring, prediction and remediation.

The paper describes (i) best practice approaches for assessing scour susceptibility and propagation rates with and without engineered protection, (ii) new methods for determining the applicable seabed and metocean inputs, (iii) a probabilistic framework for encompassing uncertainties, and (iv) how this approach can be applied in project applications.

Our probabilistic method of assessing and presenting scour risk produces a distribution of estimates of scour depth and time rate. By capturing and quantifying the full range of uncertainties, this method facilitates decision-making by showing the range of potential outcomes and allowing the associated costs and consequences to be evaluated. This approach is superior to deterministic ‘worst case’ calculations, which are often used to assess scour susceptibility.

In summary, this paper provides operators and owners with an improved methodology to unlock Capex and Opex savings through more accurate and informed scour assessments.
Vertical Input for Seismic Analysis of Offshore Structures
Authors: Zanoli O. , Smerzini C. , Parker E. J.
Published: April 2016

The vertical spectral shape suggested by the main offshore codes does not reflect actual earthquake behavior. The problem is exacerbated in time history analysis, as the incorrect spectral shape leads to unrealistic scaling of records. Vertical spectra from codes are compared to published measurements from offshore sites and the results of numerical modeling. The effects of the water column and the mismatch between code spectra and real time histories are illustrated. Results of the spectral matching show that the vertical spectral shape defined by offshore codes leads to over conservative vertical time histories at short periods.

Often vertical response is expressed as a fraction of the horizontal spectral acceleration at the same frequency (V/H ratio). Current practice regarding V/H is reviewed, considering design codes and recent research. Conventional V/H ratios are compared to sea bottom measurements by Boore and Smith (1999) which highlight the peculiarities of offshore sites. A relatively simple numerical analysis of vertically propagating compressive waves is used to evaluate vertical amplification and the effect of the water column for a case history.

Current practice shows a certain degree of variability among the codes/papers. For onshore sites, there is consensus that V/H>1 at low periods but that vertical is less than horizontal at long periods. Boore and Smith's seafloor recordings suggest that offshore motions have very low vertical motion compared to onshore conditions, especially at low periods. The numerical modeling shows that the vertical response is mainly controlled by the water layer, which induces a strong deamplification at the resonance period of P waves within the water layer. Such an effect is in agreement with the findings of Boore and Smith (1999).

The paper highlights the poor definition of the vertical seismic spectra for offshore sites in seismic codes and makes a first step towards the development of more reliable vertical spectra. The overconservatism induced by the code vertical spectra on definition of time histories is presented to stimulate future developments.
Investigations into the Fatigue Strength of CRA Lined Pipe
Authors: Johnston Carol , Nageswaran Channa , London Tyler
Published: April 2016

Pipes that experience sour service need to resist that corrosive environment. One method for achieving corrosion resistance is by lining the inside of the pipe with a corrosion resistant alloy (CRA), such as stainless steel or a nickel based alloy. This has the advantage of being much cheaper than either making the pipe from the CRA or metallurgically bonding CRA to the pipe (ie clad pipe). Lined pipe is gaining popularity, and has so far been used successfully in applications where applied strain levels are low, however more data is needed on its fatigue strength and its behavior when subjected to high levels of applied strain. A Joint Industry Project (JIP), funded by Petrobras, BG Group, Saipem, Tenaris, Technip, Cladtek and HMC, was run by TWI Ltd and INTECSEA to investigate and generate data on CRA lined pipe.

The JIP included full scale resonance fatigue testing, allowing the failure location of lined pipes to be investigated, development of an ultrasonic inspection procedure for lined pipe, small scale mechanical tests to generate materials data and calculation of stress intensity factors specific to the lined pipe geometry. This paper presents a summary of the work carried out.

The significance of the paper is that it describes a body of work carried out in the field of CRA lined pipe, helping operators and those at the front-end engineering design (FEED) stage to choose lined pipe, with the resulting cost savings.
Gas-2-Pipe™, A Concept for Treating Gas to Rich Gas Quality in a Subsea or Unmanned Facility
Authors: Fredheim Arne Olav , Johnsen Cecilie Gotaas , Johannessen Eivind , Kojen Gry Pedersen
Published: April 2016

Field developments on the Norwegian Continental Shelf (NCS) have become cost intensive both for greenfield and for tieback / brownfield developments. A large existing infrastructure with future free capacity is available consisting of processing platforms and transport systems. The objective for the Gas-2-Pipe™ concept is to reduce capex/opex intensive topside modifications and topside weight and space constraints by utilizing the established infrastructure and host facilities in a flexible way.

The process concept treats a gas dominated well stream in order to meet the so called rich gas transport specifications. Rich gas specifications in the Norwegian transport system are mainly related to a cricondenbar specification in the range of 105 to 110 bar and to a water dew point specification of typically -18 °C at 70 bar. Gas is treated in two steps where hydrocarbon dew point is obtained by sea water cooling and pressure reduction to form a gas and a liquid phase. Water content in the separated gas is reduced by injecting lean glycol through a compact mixer unit and separating out the rich glycol from the gas in a separation unit. Gas is also cooled by sea water in the dehydration process. A single- or two-stage dehydration process may be used. Considerations regarding process design, process parameter selection and glycol distribution rate are given.

After treatment, the gas is compressed to the necessary export pressure and injected directly into the pipeline. Processing takes place in a subsea or topside unmanned environment where necessary utilities are imported from one or several hosts. Required utilities are typically power- and control system and glycol for gas dehydration. Produced liquid hydrocarbons and water is routed to a host for further stabilization and treating. The concept may become an enabler when nearby host capacity is gas constrained and traditional tie-back is too cost intensive.

The concept is seen as an enabler for field development of gas dominated fields with a potential for cost reduction compared to conventional concepts. The main gaps are identified and a qualification strategy for the key technology elements is given, ranging from small scale and pilot scale testing to implementation of new technology elements in traditional field developments.
A Custom Made Organization to Manage Deep Offshore Brown Field Projects of TOTAL E&P Angola Block 17
Authors: Morard Jean-Hervé
Published: April 2016

TOTAL E&P Angola celebrated mid 2015 its 2 Gbbl produced on its deep offshore Block 17 with its 4 FPSO’s (Girassol, Dalia, Pazflor and CLOV).

From 2008, numerous brownfield projects opportunities have been identified and developed in order to limit the natural decline of the producing fields and to maximize the production of the existing FPSOs: infills wells, enhanced activation by seabed multiphase pumping, process topsides debottlenecking, tie-back of satellite and marginal fields…

In 2012 a dedicated structure has been created in TOTAL E&P Angola to manage the execution of all Brownfield Projects on Block 17.

This paper presents the objectives, strategic axes, organization, challenges and achievements of the Block 17 ‘Project Brown Field’ Direction.
Integrated Decommissioning – Increasing Efficiency
Authors: Price William R. , Ross Benjamin , Vicknair Benton
Published: April 2016

As offshore fields reach the end of their economic lives, there is an increasing need to decommission platforms and other structures to promote safety, protect the environment, and comply with governmental regulations. Decommissioning is a complex undertaking, requiring a range of equipment and expertise. Especially in the current economic environment, oil and gas operators are seeking ways to decommission their older facilities while controlling costs. This paper describes a more efficient method of platform decommissioning that integrates multiple services and manages them as a single project, with the objective of completing the decommissioning job safely and efficiently at a fixed cost to the operator.

This approach was implemented for an operator in 2015 to decommission an eight-pile platform in the South Timbalier area of the Gulf of Mexico. Project implementation involved extensive planning, the integration of four services that are typically provided separately, project management and site coordination, as well as lump sum contract terms to facilitate cost control by the operator.
Rov Based Survey: A New, More Effective Approach
Authors: Oskarsson Ola
Published: April 2016

Objectives/Scope: The paper presents results from developing a specialized Survey-ROV (Remotely Operated Vehicle) aimed at higher speed and unsurpassed resolution. Multi beam, laser and photogrammetry data will be presented.

Methods, Procedures, Process: The Surveyor Interceptor is a newly developed specialized Survey ROV. It has a hydro dynamically favorable hull, thin tether, and powerful propulsion to allow high resolution surveys, close to the seafloor, at speeds up to 10 knots.

The ROV was built during 2014 and has been tested during Quarter 1 2015. This paper presents results from tests and the first commercial tasks for the new SROV. The ROV has been used for pipelines, route surveys and environmental surveys in the North Atlantic at water depths between 50 -1200m. Acquired data will be presented. Performance as well as resolution and accuracies obtained are above the initial specifications and new technologies are developed.

The combination of high resolution equipment in a stable hull, renders accurate data for enhanced risk mitigation of offshore installations

Results, Observations, Conclusions: The SROV has surveyed with average speed of above 4 knots at several hundred meters water depth while collecting data from Multibeam echo sunders, laser bathymetry, still photos, photogrammetry, Side Scan Sonar’s and Sub Bottom Profilers. The Underwater Navigation results are greatly improved by the use of inverted USBL, DVLs and INS systems. The vehicle is very stable at speed, thus rendering clean data with very little outliers. All in all the total concept can reduce the cost of pipeline and route surveys with improved data quality.

Integrity Management decisions based on data from the SROV will greatly reduce risk of offshore pipelines and installations.

Novel/Additive Information: Specialized Survey ROV’s will lower the cost for Pipeline Inspection and Environmental Impact Surveys while rendering 3D models and resolution of hitherto unseen density and accuracy.
Gullfaks Subsea Compression - Subsea Commissioning, Start-Up and Operational Experiences
Authors: Birkeland Bjørn , Bøe Caroline , Jensen Roger Oen
Published: April 2016

The Gullfaks subsea compression project is a brownfield development which aims to extend the plateau production and increase total recovery from the Gullfaks Sat. Phase II (L and M templates) with multiphase compression technology from OneSubsea. This is the world's first subsea wet gas compressor project, and the compressors are installed at approximately 135 m water depth. The subsea compressors will boost the unprocessed gas well stream containing liquids to Gullfaks C from year 2015 to 2030. The compressor station will be located at the M and L templates and the tie-back distance to Gullfaks C is approximately 16 kilometer. The compressor station is equipped with 3 future hubs for tie-in of additional fields in the area, which enables flexibility to the system.

The Gullfaks Compression System (GSC) main components consists of 2 multiphase compressors (WGC4000) with individual recirculation systems, 2 subsea process coolers, 1 flow mixer and 3 bypass headers. The flow mixer is located at the inlet of the station and the main purpose of this device is to dampen out liquid slugs and provide an equal homogenous split of multiphase flow to the two compressors when operating in parallel. The subsea cooler main purpose is to cool the well stream before compression in order to limit the compressor discharge temperature below the flow line design temperature in addition to increase compression efficiency.

The wet gas compression technology is applicable for most gas fields which will have use for pressure support at one stage. The system is quite simple i.e. there is no need for conditioning of the well stream.

The Gullfaks Subsea Compression station was started up October 7th 2015. This paper will describe the subsea commissioning phase, including lessons learnt from the subsea commissioning phase. In addition this paper will give an outline of the experiences gained during start-up and operational phase.

The wet gas compression technology could have an impact on brown field developments where topside weight capacity may be constrain. Such project could also have a positive impact wrt HSE as no tap in to existing topside process will be required. Last but not least, this is a cost efficient solution where the recoveries from the wells are improved in addition to accelerated production.
Floater and SURF Combined and Optimized Solutions
Authors: Seguin Blaise , de Roux Grégoire , Germanetto Florian , Beltrami Francesco , Shah Vinanti , Linder Samuel
Published: April 2016

It has long been recognized that value creation for deepwater projects is predicated based on robust front end engineering and field development planning. Realizing this value requires a multidisciplinary approach that considers early engagement with the SURF execution team and the field development planning specialists, engineering specialists and project execution expertise. This paper presents an overview of recent experience and an illustration of the benefits of this approach. The general principles of field development optimization are presented, with an emphasis on Floater and SURF packages as well as the cost drivers to optimize the interfaces between these packages.

This paper plans to explore the benefits of front end engineering design as it relates to early engagement of the SURF and Floater disciplines. The paper will examine through case studies topics such as: subsea production network alternatives, floater and riser conceptual and early phase design, and interfaces between the floater, riser and production system.
High-resolution Velocity Update Using Full Waveform Inversion: A Case Study in East Breaks, Gulf of Mexico
Authors: Bai Bing , Yu Guo , Wang Sunxi
Published: April 2016

In this case study located in East Breaks, Gulf of Mexico, we faced seismic imaging challenges caused by a mass-transport complex (MTC) below the seabed. The MTC is characterized by moderate-to-strong seismic velocity and amplitude variations due to both structural and stratigraphic inhomogeneities. Traditional tomographic velocity inversion methods could not provide sufficient resolution of the small-scale velocity anomalies within the MTC. As a result, seismic events below the MTC appeared distorted and out of focus. Multiple iterations of high-frequency full waveform inversion (FWI), up to 18 Hz, enabled us to derive a detailed velocity model of the MTC, thereby improving the seismic image beneath it. Detailed analysis at a deeper reservoir level showed that event continuity, gather flatness, AVO response and pre-stack P-impedance inversion were all improved after migration using the FWI-derived velocity.
LNG Tandem Offloading Solution: Ready for Deployment!
Authors: Duhamel Nicolas
Published: April 2016

The first worldwide offshore FLNG projects are moving up to construction and commissioning phases, with first gases most likely planned for the next two years. These floating facilities will operate in exposed environmental conditions (typically Hs up to 2.5m), under which it has been demonstrated that side-by-side offloading remains a safe and viable operation. The excellent track records of marine loading arms in the LNG industry; as well as the great economical advantage to distribute LNG to conventional LNG carriers, naturally led to the development of offshore loading arms, being the references on the FLNG market today.

Nevertheless, the higher performances, enhanced availability and the ability to relocate the FLNG in any location of the world naturally forced the FLNG projects owners to look carefully at LNG tandem offloading, as a natural way to offload as per FPSO culture. Whereas the main showstopper was the lack of maturity of LNG tandem offloading technologies a few years ago, latest developments made on the FMC ATOL (Articulated Tandem Offshore Loader) in partnership with oil & gas majors, DP suppliers and LNGC operators change the stakeholders dreams into reality.

The FMC ATOL has not only been validated through comprehensive kinematic, stress and fatigue analysis to confirm a 99+% operability in the harshest Australian type conditions, it has also been fully validated thanks to an 1/5 scale model tested under the harshest environmental conditions with third parties involvement.

Field proven components designs and technologies resulting of 50 years of conventional LNG transfer records and today of offshore side-by-side LNG transfer with loading arms are transposed to the ATOL LNG tandem transfer solution and prototype-tested to real project conditions, like the FMC ATOL swivel joint which successfully passed a long life test equivalent to a 10-year maintenance-free period (considering 1 offloading a week). These are 7 years of development and 30 000+ hours of engineering which rose up the technology readiness level high enough for the deployment of the FMC ATOL on field.

On top of that, a consolidated execution plan has been developed detailing a 30 months delivery time, including project specific engineering, purchasing, construction and tests. As part of this execution plan, the FMC ATOL has been developed emphasizing the turnkey approach, to minimize the integration works duration on the FLNG to a strictly limited number of mechanical and electrical interfaces. Such all-in-one design allows performing an extensive tests campaign on the ATOL before its delivery, inclusive of functional tests, static and dynamic tests and simulations of emergency disconnections.

This is how FMC Technologies provides performance, safety and reliability guarantees before the integration of the FMC ATOL on the FLNG, in mirror of how the success story of the FMC OLAF on Prelude FLNG project has been built.
Use of Advanced Composites in Offshore Pipeline Design
Authors: Ravirala Naveen , Sawant Sourabh , Abdalla Basel
Published: April 2016

One of the advanced composites which has never been applied in the oil and gas industry is the Auxetic composite material that possess a negative Poisson's ratio behaviour due to the orientation of pre-preg laminate stacking sequence. These advanced composite structures with their unique ability to increase wall thickness upon axial straining will have enhanced mechanical properties in terms of indentation resistance, fracture toughness, shear resistance and attenuation of ultrasonic signals. This paper will discuss and analyze these novel auxetic composite structures and opens new avenues for potential applications in the offshore pipeline industry.
An Improved Methodology on Design and Analysis of Offshore Wind Turbines Supported by Monopiles
Authors: Sahasakkul Watsamon , Nguyen Hieu , Sari Ali
Published: April 2016

A wind turbine shall be considered as an offshore wind turbine if the support structure is subject to hydrodynamic loading. Foundation design or soil-structure interaction is not clearly outlined in detail in the design standards for wind turbines, IEC 61400-1 (Design Requirements) and IEC 61400-3 (Design Requirements for Offshore Wind Turbines). The general approach in the IEC standards is to follow the API (American Petroleum Institute) design approach for offshore platform foundations.

In an API approach, the soil p — y curves are developed for the slender piles which are widely used for offshore oil and gas platforms. The failure mode of these slender piles is the formation of flexural plastic hinges. In contrast, the monopiles supporting offshore wind turbines are typically rigid with 3.5 – 6 m diameter and 30 – 40 m length. The failure mode of these monopiles likely involves rigid motion. Under extreme loading conditions, soil surrounding the monopile may fail because of large deformation due to such motion. Therefore, the API approach developed for slender piles may not be applicable for the monopiles.

An improved methodology for analysis and design of a 5-MW offshore wind turbine (OWT) supported by a monopile is presented in this study. The soil-monopile interaction under wind and wave cyclic loads is first studied using advanced finite element analysis (FEA) in ABAQUS. The results of the analyses are utilized to develop a set of p — y curves for the monopile. The FEA-based nonlinear p — y curves are input to SACS through user-defined subroutines. The coupled analysis includes soil-structure interaction and dynamic response of the tower and blades to wind and wave loadings. The fully coupled analysis is carried out using SACS-FAST integrated computational interface. Response of the wind turbine on the monopile is studied in a time domain using frequency domain inputs such as Kaimal spectrum for wind loading (TurbSim, NREL) and JONSWAP spectrum for wave loading in SACS. In a case study, the dynamic response of the 5-MW wind turbine and its monopile foundation obtained using the nonlinear p — y soil curves in the coupled analysis will be compared to the one obtained using an API approach.
Current State of the One-Trip Multizone Sand Control Completion System and the Conundrum Faced in the Gulf of Mexico Lower Tertiary
Authors: Techentien Bruce , Grigsby Tommy , Frosell Thomas
Published: April 2016

This paper provides perspective on the current state of multizone completion technology and issues encountered in the industry with developing a system that offers increased capabilities to meet the ever-increasing challenges presented by the Lower Tertiary formation in the Gulf of Mexico (GOM).

Since the introduction of the first-generation multizone system approximately 35 years ago, the technology has continued to evolve to meet new well and reservoir challenges. The Lower Tertiary formation in the GOM is currently driving the need for further evolution of the current-generation multizone system. The Lower Tertiary reservoir requires deeper well depths, higher zone pressures, higher bottomhole temperatures (BHTs), and higher production rates as well as reservoir monitoring and reservoir control for improved reservoir management. These are just a few of the technical challenges for developing the next-generation multizone completion system.

In the intervening 7+ years after its introduction, the fourth-generation multizone system was successfully deployed in multiple ultra-deepwater wells in the GOM, along with dry and wet tree completions in the Asia Pacific area. This paper presents information on the associated demands for improved technologies, which will assist the industry understanding of the technical challenges related to drilling, completing, and producing in the Lower Tertiary formation. The paper discusses which requirements are optional and mandatory for future development and evaluation and how this will affect well architecture in the future. The multizone technology has proven to be an enabler for cost-efficient completions in the shallow well environment and a true enabler in the high-cost ultra-deepwater environment requiring high-rate fracture stimulation treatments.

Similar to previous systems, this fifth-generation multizone system is expected to have a significant impact on production and reservoir management. The proven technology will help operators overcome the completion challenges presented by the Lower Tertiary formation.
Degradable Metal for Use in a Fully Dissolvable Frac Plug
Authors: Fripp Michael , Walton Zachary
Published: April 2016

A new dissolvable frac plug has been developed for "plug-and-perf" style hydraulic fracturing applications. The dissolvable frac plug operates like a traditional frac plug and can be set anywhere in the wellbore to isolate individual zones. The new dissolvable frac plug is composed of a high-strength metal that degrades completely in wellbore fluids.

Traditional frac plugs are constructed from a composite material. After a hydraulic fracturing treatment is complete, traditional frac plugs create a restriction to production flow and must be removed. Thus, a separate intervention is required to mill out traditional plugs after fracturing. A novel dissolvable frac plug has been developed that eliminates the need for a separate mill run intervention into the wellbore. The new frac plug will degrade completely to leave an unrestricted wellbore for production. The high-strength dissolvable metal allows dissolution in water-based wellbore fluid, formation fluid, or production fluid.

Comprehensive laboratory testing was conducted on the dissolvable metal alloy for the new dissolvable frac plug. The dissolvable metal alloy is a metallic alloy that is combined with a dopant. The dissolution behavior is controlled by the interaction between the dopant and the rest of the metal alloy. Metallographic analysis illustrated the effect of the dopant on the dissolution of the metallic alloy. Dissolution is further influenced by the wellbore temperature. The high-strength alloy allows for the creation and use of dissolvable slips, which enables the complete dissolution of a frac plug that can be set anywhere within the wellbore.

The novel frac plug is designed for plug-and-perf applications and is composed of a new high-strength engineered metal that dissolves in water-based wellbore fluid, formation fluid, or production fluid. Complete dissolution of the frac plug eliminates the need for a separate mill run intervention into the wellbore, which helps reduce costs, operation time, and risks to personnel. This paper discusses the development of the dissolvable metal and the dissolution behavior of the metal upon exposure to wellbore fluids.
Improving Safety of Deepwater Drilling Through Advanced Instrumentation, Diagnostics, and Automation for BOP Control Systems
Authors: Nelson William R.
Published: April 2016

Among the contributors to excessive downtime for deepwater drilling are undetected failures in blowout preventer (BOP) control systems. These undetected failures result from the limited instrumentation of current systems, and require use of conservative criteria to decide if the BOP should be pulled to the surface for maintenance. The safety and risk effects of undetected failures are currently measurable only indirectly by the consequence of excessive non-productive time.

A reliability- and human-centered design approach has been developed for next-generation BOP control systems to improve the safety of deepwater drilling by providing additional redundancy and fault tolerance, more accurate information regarding control system health, and clear guidance for determining whether the control system should be reconfigured to compensate for failures or pulled to the surface for maintenance. Enhanced instrumentation is provided to enable improved diagnostics and prognostics, measurable safety integrity levels, and reduced human errors in pull/no pull decisions.

This approach has been applied to the development of advanced BOP control systems that include innovative design features to reduce downtime and enhance safety for deepwater drilling. The approach focuses on development of advanced instrumentation and decision support for continuous assessment of BOP health, assessment of compliance to regulatory and industry standards for BOP functions, automatic reconfiguration to compensate for component failures, and determination whether operations can continue or if the BOP must be pulled for maintenance.
Loop Current Operational Forecasting in 2015: Skill Assessment and Lessons Learned
Authors: Frolov Sergei , Sharma Neha
Published: April 2016

2015 was a year of unprecedented Loop Current (LC) activity. From February to June 2015, the LC and its associated eddies were monitored at a significantly higher rate in southern Walker Ridge in support of current-sensitive offshore operations. A privately operated ocean forecast system for the Northern Gulf of Mexico, a.k.a. the Eddy Forecast System (EFS), was actively employed as an integral part of the currents monitoring program. A total of 38 forecasts were performed with the EFS over this four-month period, more than half of these were dedicated to support of operations in the southern Walker Ridge. In this study, we evaluate the site specific EFS skill by comparing current speed forecasted at the site with observed currents. Despite very complex LC-eddy configurations that presented a major challenge for forecasting and most demanding model skill definition, the EFS demonstrated skill up to 6 days on average for the entire four months period. The average site dependent skill was determined to vary from about 5 days to over 9 days, depending on the location relative to the LC and major eddies. Simple ensembling techniques, i.e. combining multiple forecasts, were shown to improve the EFS skill by 2-3 days. Individual forecast failures over the same time period were also analyzed. An additional operational data collection guided by "crucial uncertainties" identified by the EFS is proposed as an effective method of reducing the number of failed forecasts and improving the overall model skill.
Subsea Compression – Long Term Technology Development
Authors: Ramberg Rune Mode , Hedne Pål Eirik
Published: April 2016

The paper reviews the way leading up to the Subsea Factory Compressor Stations with focus on important technology step-stones and breakthroughs. A dedicated and long term focus on technology development through R&D has been carried out within a series of disciplines supporting the subsea production application. The development has been along two important axis; multiphase flow and subsea systems.

A comprehensive R&D effort was initiated in the beginning of the eighties resulting in a highly successful and profitable development and implementation on the Norwegian continental shelf, namely the subsea industry. Through a series of successful tie-backs and long distance multiphase flow lines, the ultimate concept was achieved for gas-condensate systems represented by the unprocessed transportation of well stream directly to shore. The first multiphase pumps were installed in the late -90 and in 2000 the first subsea separation station was started up. Today subsea boosting and separation is proven technology. In 2011, building the first subsea gas compression station was initiated, taken the last step to a full subsea factory installation.

To realise subsea compression, the main components have been subject to a systematic technology qualification process. The paper describes how Statoil's large scale laboratory facilities has been mandatory for full scale qualification testing as well as focus on quality to achieve the necessary level of confidence. The Subsea Compression projects solely, have carried out nearly 60 qualification activities, further detailed in the paper.

The paper also looks forward and point out that the subsea processing solutions that have been qualified and implemented can be utilized to achieve cost efficient solutions with low environmental footprint.
Fault Block Migration and Its Impact of Complex Fluid Distributions and Equilibration
Authors: Wang Kang , Kauerauf Armin , Dong Chengli , Elshahawi Hani , Zuo Julian Y. , Mullins Oliver C.
Published: April 2016

Reservoir fluid distributions at the field scale are affected by charging history, fluid dynamics as well as geological events during and after charging. With multiple charges of fluid of different maturities, reservoir fluids are typically not in equilibrium initially. Over geological time, fluids tend to equilibrate through connected sands by diffusive processes and in some cases by convective processes. It has long been established that connected reservoirs are often associated with equilibrated asphaltenes. These issues of reservoir structure and equilibration of different crude oil components are examined in greater detail in this study. Additionally, geological events after fluid charging could lead to complicated fluid property distributions. For example, fault block migration can yield complex fluid gradients; nevertheless, within individual fault blocks, good connectivity and trends to fluid equilibration can prevail. Furthermore, different components of crude oils, such as light end hydrocarbons, asphaltenes, biomarkers, can equilibrate at different rates, which makes fluid distributions more complicated. In this paper, equilibration of reservoir fluids after charging terminates and over geologic time is modeled and compared to actual reservoirs. This modeling is combined with potential geological events of faulting and fault block migrations, and scenarios for reservoir processes are better understood on the fluid distributions today. Here, the modeling incorporates diffusion explicitly; nevertheless, some convective flow is indicated associated with fault block migration with its changing formation geometry and connectivity pattern. These field observations are guiding a broader understanding of reservoir fluid geodynamics.
Seismic Assessment of Tension-Leg Platforms
Authors: Arablouei Amir , Cai Wenyu , Sari Ali
Published: April 2016

Tension-leg-platforms (TLPs) are becoming increasingly popular for offshore drilling at deep-water sites. Seismic response of TLPs is of significant importance in the design or assessment of these platforms since seismic excitations, especially the vertical component, can directly affect the total tensile force of tendons. This paper focuses on the impact of seismic ground motions on the TLPs, especially on tendons. The first part of this paper discusses the development of an advanced methodology for seismic assessment of TLP structure considering the following effects; pile-soil interaction, soil radiation damping, soil degradation due to cyclic loading, current effects, hydrodynamic damping, and marine growth. The second part of the paper presents a case study to demonstrate application of the developed methodology. Two types of analyses are carried out; response spectrum analysis for extreme level earthquake (ELE) and dynamic nonlinear analysis for abnormal level earthquake (ALE). The response spectrum analysis is carried out using SACS and the time history simulations are performed using nonlinear dynamic structural analysis program, CAPFOS. Multiple interactions among soil, fluid and platform is numerically quantified in this study, providing insights into the response of TLPs under complicated dynamic loading conditions.
CO2 Enhanced Oil Recovery for Offshore Oil Reservoirs
Authors: Kuuskraa Vello A. , Malone Taylor
Published: April 2016

This paper presents the results of a recent analysis of applying carbon dioxide enhanced oil recovery (CO2-EOR) to oil reservoirs in the offshore Gulf of Mexico (GOM). The study started with a data base from the Bureau of Ocean Energy Management (BOEM) that contained 531 oil fields with a total original oil in-place (OOIP) of 69 billion barrels. The study excluded 391 of these oil fields, representing 35% of the OOIP, as not being amenable to CO2-EOR based on their size, minimum miscibility pressure, and residual oil saturation. The study then evaluated the remaining 140 GOM offshore oil fields, containing 696 individual reservoirs, for their technical and economic viability for CO2-EOR.

Crude oil production and CO2 injection profiles were calculated for each reservoir using a stream-tube finite-difference simulator. The calculation of economic viability was based on a crude oil price of $90/bbl, a CO2 price of $1.59/Mscf ($30 $/MtCO2) at the capture facility plant gate, an 18.75% royalty, and a minimum 20% rate of return, before taxes. With Current CO2-EOR Technology, the economically recoverable resource (ERR) from the GOM offshore is 0.8 billion barrels, a small fraction of the technically recoverable resource (TRR) of 23.5 billion barrels. With Next Generation CO2-EOR Technology, the ERR increases significantly to 14.9 billion barrels.
Qualification and Implementation of a Subsea Wet Gas Compressor Solution
Authors: Hjelmeland Mads , Torkildsen Bernt Helge
Published: April 2016

The challenge of increased recovery in development of subsea fields has driven the advancement of subsea processing technologies, in particular within the subsea boosting domain. The successful operation of large subsea boosting systems on a global scale, coupled with significant added value of pre-compression systems in gas fields, has driven the next technology step; subsea multiphase compression. The application of the multiphase compressor in a subsea environment simplifies a subsea compression system significantly, as there is no need for pre-processing. This enables development of simplified subsea systems at lower capital expenditure and field development costs.

This paper will provide an overview of the Technology Qualification Program (TQP) completed for Statoil's Gullfaks Subsea Compression (GSC) project, as well as present the WGC4000 compressor performance characteristics and mechanical design. Experiences from the GSC project, as well as deployment and commissioning of the subsea compression system in second half of 2015, will also be described.
Loop Current Hyperactivity: Analysis of In Situ Measurements in the Gulf of Mexico
Authors: Sharma Neha , Storie Jill S. , Obenour Kelsey M. , Leber Michael J. , Srinivasan Ashwanth
Published: April 2016

Starting in June 2014, ocean currents in the Gulf of Mexico became uncharacteristically detrimental to offshore operations. An unprecedented event of extreme Loop Current activity, not only in spatial and temporal extent but also in current intensity and vertical structure, was observed and documented for a year and half. The unusual activity was attributed to either increased inflow from the Caribbean Sea through the Yucatan Channel or amplification caused by local frontal cyclonic eddies. Anticyclonic eddies that shed from the Loop Current during this ongoing event maintained relatively large structures following their initial detachments and exhibited reconnections with the Loop Current within days to weeks of separation. This process was repeated by several eddies more than twice. In situ measurements indicated frequently reoccurring ocean current intensities upwards of 3.0 knots sustained for several weeks at a time with peak observed amplitudes over 4.0 knots. In this study, we present data collected from ADCP measurements and an extensive network of drifting buoys in correlation with daily frontal analyses based on all available in situ data and satellite imagery – both public and proprietary. The Loop Current and each eddy shed during this period is discussed with emphasis on structure, intensity, and migration pattern. Investigation was made into a possible link to El Niño and/or other large-scale air-sea phenomena and teleconnections; however, the root cause(s) for the circulation hyperactivity in the Gulf, if any, remains unknown. The study concludes with lessons learned and a brief description of long-term forecast modeling efforts to mitigate risk and enhance safety and efficiency in offshore operations.
Parameters Influencing Seismic Assessment of Subsea Structural Systems
Authors: Sari Ali , Azimov Umid , Nguyen Hieu
Published: April 2016

Significant improvements in technology include the development of subsea systems capable of retrieving and pre-processing oil and gas at sites located miles away from the host platform. The use of subsea systems at deep water sites in seismic regions has become increasingly common in recent years due to the growing exploration and continuing advances in the construction, placement and maintenance of subsea systems. Seismic events may impact the operability, stability and safety of subsea structural systems. Thus, the focus of this study is to evaluate the response and vulnerability of subsea structures during a seismic event and provide a quantitative sensitivity assessment for various parameters affecting the analysis.

An analytical parametric study for a subsea structure and connecting pipe system was performed. The structural configurations of the system, surrounding soil conditions and the expected seismic demands along with the intensity and frequency characteristics of the ground motions are crucial for accurately modeling and predicting the expected structural response during earthquakes.

Computer models using non-linear finite element method analysis procedures are developed to assess subsea systems under seismic loads. Sensitivity studies are conducted on parameters such as soil damping, soil-pile interface gapping, and multilevel excitation to simulate the response of subsea structural system. Computer model was generated, and nonlinear seismic response was simulated in CAPFOS software.

In the case study, it was observed that the soil radiation damping effects, pile-soil interface gapping and uniform versus depth-varying seismic load application can have considerable effect on the response of the subsea structural systems. The results of this study show that the response of the subsea structural system is sensitive to parameters considered. Therefore, specific design information for a subsea system is critical in making a final assessment of the expected performance under site specific ground motions. This study may help offshore engineers to gain a quantitative understanding of how different parameters influence the results of seismic response of subsea structural systems.
Plume Modeling in Lake Kivu, Rwanda for a Gas Extraction Facility
Authors: Morse Timothy L. , Ponchaut Nicolas F. , Bigham Gary N.
Published: April 2016

Lake Kivu, located between Rwanda and the Democratic Republic of Congo, is unique among several East African Rift lakes with high concentrations of dissolved carbon dioxide in that it also contains methane, kept in solution by the pressure of the deep water. The gas poses a potential hazard as a vertical disruption of the lake water (due to a landslide or volcanic activity) could cause gas-laden water to be displaced to shallower depths (and lower pressures), allowing the gas to bubble out of solution, triggering a gas eruption. A floating gas extraction facility has been constructed to extract gas-laden water from deep in the lake, separate the methane and some of the carbon dioxide and reinject the degassed water, thus increasing the safety of the lake and simultaneously providing methane, which will be used to generate electricity. This paper explores the computational fluid dynamics technique used to analyze the degassed water discharge plume from that facility and describes the dynamics of the plume.

We used a Reynolds-Averaged Navier Stokes (RANS) model to analyze the dynamics of the degassed water plume. The density of the water, and hence the plume dynamics, is heavily affected by the water temperature and the concentration of methane, carbon dioxide, and salt. Thus the computational method tracked these quantities throughout the simulation. The background conditions in the lake (including mixed zones separated by density gradients) were also included in the model. Lake Kivu is unique in that the water temperature increases with depth. The lake remains stratified because the salt concentration also increases with depth and more than compensates for the effect of water temperature.

Two main concerns were raised with the degassed water plume: (1) could there be recirculation between the water intake risers and the degassed water discharge points? (2) could the dynamics of the plume lead to an overturn of the lake and a catastrophic gas eruption? Our simulations showed that the degassed water plume ultimately stratifies within a density gradient, that recirculation does not occur, and that the discharge plume does not result in uplift or overturn of the lake for the conditions evaluated.
Using Operational Failure Modes and Effects Analysis to Identify Project Top Risks
Authors: Kokosz C. , Engle R.
Published: April 2016

Combining the Mission Support Equipment (MSE) Failure Modes & Effects Analysis (FMEA), Project Installation Methodology and the customer's Risk Management Plan produces a project oriented customized ranking of the risks resulting from MSE failures modes. Identifying the Project Top Risks (PTR) allows the customer to prioritize equipment verification and project specific maintenance prior to the customer's project readiness review.

The FMEAs provided by the MSE's Original Equipment Manufacturer (OEM) typically focus on the risks posed to the MSE, not to the customer's project. The MSE operational FMEA can be written at the most reasonable level of repair/replacement of the equipment. Each operational FMEA is then assessed against the project installation methodology and the risk management plan providing a likelihood, severity and risk ranking score for each failure mode.

As a result of the operational FMEA, the project top risks are identified. The project manager uses the PTR to prioritize project specific inspections and verifications, project specific maintenance, assess the need for additional spares and identifying operational workarounds for problems that may arise during the project. These analytical techniques provide a focused view of the MSE failure mode risks and possible mitigations in order to avoid costly effects and downtime.

The FMEA can also be used to quickly build Fault Trees which can be used as an aid to determine the most probable cause of a failure should a failure occur.