bluuebunny/crossref_metadata_2025_split huggingface dataset:
Development and Qualification of a Subsea Compressor
Authors: Kleynhans George , Brenne Lars , Kibsgaard Svend , Dentu Pascal 
Published: April 2016

Abstract
Oil and gas production in the Norwegian Sea has been ongoing for decades. The Åsgard B platform produces gas and condensate from the Mikkel and Midgard reservoirs from subsea wellheads with 50 to 80 km long pipeline tie-backs. Because the production started to decline, several innovative technologies were investigated to extend the production and increase the total recovery from the field. Artificial lift, by applying compressors installed on the seabed close to the wellheads, was the most favorable solution. An all-electric hermetically sealed integrated motor-compressor was selected to fulfil this duty and an extensive technology qualification program over 10 years was initiated.
Machine qualification activities included both component and full scale testing levels with the aim to arrive at a low risk subsea compressor solution with utmost robustness and reliability. The component testing level placed major focus on screening available materials to withstand exposure to the raw wellstream fluid from the Åsgard field. Full scale motor compressor testing was performed in a dedicated test facility with hydrocarbon fluids to investigate overall machine performance and enhancement via the introduction of new machine components from the material screening testing.
Valuable operational experience from the qualification efforts were collected and used to establish the design and material selection boundary conditions for the final dedicated subsea compression solution. A particular negative operational experience was fouling induced machine thermodynamic and rotordynamic performance degradation and the need to introduce integrated online washing and machine wet gas compression compatibility to reduce operational risks. To preserve machine robustness and mitigate potential corrosion and erosion problems, a machine concept with unconventional low operating speed and enhanced materials was selected. The world’s first subsea compressor with the above concept attributes was successfully manufactured, tested, installed, and operated subsea at a depth of 260 meters.
The qualified machine has been designed and tested for presence of free liquids such as water, hydrocarbon condensate, and glycol in the gas stream and demonstrated full capability to operate within the complete compressor performance map with liquid content exceeding levels found in normal gas-condensate fields. An available high performance wellstream compressor can reduce the complexity and cost of future subsea compression systems.
Subsea Compression – Project Overview
Authors: Vinterstø Torstein , Birkeland Bjørn , Ramberg Rune Mode , Davies Simon , Hedne Pål Eirik 
Published: April 2016

2015 represents an important milestone for Statoil as both the Gullfaks and Åsgard subsea compression projects achieved production start-up.The Gullfaks subsea wet gas compression system is projected to increase recovery from the Gullfaks South Brent reservoir by 22 million barrels of oil equivalent. The solution involves two 5 megawatt wet gas compressors that handle a production rate of 10 million standard cubic metres of gas per day. The compressor system is connected to existing subsea templates and piping 15 kilometres from Gullfaks C.The Åsgard subsea compression system is projected to provide 306 million barrels of oil equivalent in increased recovery from the Mikkel and Midgard fields. The solution involves two 11.5 megawatt centrifugal compressors that handle a production rate of 21 million standard cubic metres of gas per day. The compressor system is connected to existing subsea templates and piping 40 kilometres from Åsgard B. The difference in scale and boosting requirements helps to explain why two quite different technical solutions have been selected.This presentation will provide an overview of the two projects including:Why subsea compressionThe business cases and technology selectionThe technology assessment and qualification.The execution program for the projects including engineering, procurement, construction, testing and installation.Commissioning and start upFuture subsea compression opportunities
Offshore Chemical Injection Skid for use in Biological Enhanced Oil Recovery BEOR
Authors: Samuel Michael , Nimitz Ken , Gaubert Blane , Swider Chris 
Published: April 2016

Offshore enhanced oil recovery (EOR) applications have been historically challenging to implement. A successful EOR program should increase oil production with minimal disruption to operations and to the environment. Proper consideration must be given to the injection equipment footprint, power consumption, and environmental impact of the program.
The proposed technology for improving water flooding can be seamlessly implemented into existing offshore infrastructure. The continuous injection of the tailored nutrient formulation can increase recovery of original oil in place by 9-12%. Mobilization of residual oil occurs from biological activation of subsurface microbes by nutrient introduction, and subsequent growth of the biology.
Mobilization of residual oil, which increases the production rate and recovery, is achieved by activating key populations of microorganisms. These populations, largely dormant, are reactivated and propagated by continuously adding small amounts of highly concentrated nutrients into the injection water stream. The nutrient injection hardware is designed to precisely integrate with existing offshore production infrastructure, limiting the disruption of existing operations, while increasing incremental oil production.
The equipment is composed of an injection skid and a nutrient reservoir. Both have been specifically designed to limit occupied facility space. The bulk nutrient is maximally concentrated to extend time between re-supply of the nutrient reservoir. By design, the bulk nutrient is also biologically degradable once diluted. Two small points of injection introduce the BEOR process into the current waterflood scheme.
This paper describes the mobilization, commissioning and operation of fully automated injection skids with configurations that include aerated, non-aerated, high-pressure, and low-pressure injection. The paper documents operational challenges in controlling nutrient injection rates based on water injection volumetric fluctuations along with operator benefit from remote web based data and alarm monitoring.
Field Development Optimization: A SURF/SPS Alliance Experience and Perspective
Authors: Cormell Darren , de Ligny Florent Hurault , Field Kevin , Lazcano Juan 
Published: April 2016

Field development studies performed early in the conceptual stage of a project are an essential process to reduce costs and bring value. The early engagement of an integrated Subsea Production Systems (SPS) and Subsea Umbilicals, Risers, and Flowlines (SURF) combination in this phase brings specific additional benefits to this fundamental element of the development process.
This paper presents the experience and perspective of a SURF/SPS alliance in such field development optimization studies. This new approach is part of a global trend within the industry, in reaction to the current low oil prices and degraded business environment, to cut costs and push the projects towards the threshold that will make them economically viable. Historically, field development optimization has mainly been performed by operators supported by specialized engineering companies. SPS and SURF contractors are now developing and engaging in this activity, offering new vision, optimization ideas and specific technology solutions enabling cost reductions.
The long term alignment of SPS and SURF capabilities delivers a sustainable improvement in Field Development value through a holistic contractor driven approach to overall solutions. General principles of field development optimization are presented, including identification of cost and schedule drivers, the interfaces between SURF and SPS, and CAPEX/OPEX inputs with consideration of how the aligned SURF/SPS capabilities positively influence these drivers.
The key elements of how an aligned approach can bring value through reduced costs and improved schedules, risk mitigation, improved interface management, and more predictable delivery outcomes are presented within the paper. Consideration is given to alternative early engagement approaches, a selection of technical field development optimizations enabled by an integrated SURF/SPS combination and an integrated project execution approach with associated synergies and opportunities described to develop the benefits of an alliance perspective.
Game-Changing Floating LNG Solutions
Authors: Talib Javid H. , Germinder Bob 
Published: April 2016

Abstract
Floating liquefied natural gas (FLNG) solutions are built from matured oil floating production, storage and offloading (FPSO) technology, primarily to monetize stranded offshore hydrocarbon reserves by locating a floating production system at the offshore reservoir location. The wellhead gas is brought from subsea completion systems and manifolds to the topsides of the FLNG vessel for oil/water/gas separation, where needed, and gas pretreatment and liquefaction.
FLNG solutions are also being considered for exporting nearshore gas reserves or gas from an on-land pipeline network by locating the liquefied natural gas (LNG) production facility near the shore. The larger on-land baseload LNG export production plants require significant capital and take four to five years to be brought online. The FLNG concept provides a faster way to build a small-scale to midscale LNG production facility nearshore in protected waters and/or dockside and provides flexibility for progressive project development and variable LNG sales commitment volumes.
Liquefaction production capacity is generally governed by the size of the reservoir, gas availability and the strategy to export LNG (volume). The quality (composition) of feed gas brought onboard will dictate the complexity and cost of the FLNG facility. Raw gas from the wellhead may contain a large amount of liquids and condensate and heavier hydrocarbons (rich gas), while a pipeline gas from the onshore pipeline network may be very lean. The FLNG facilities for processing and liquefying raw gas could be complex and expensive. Lean gas does not require complex systems. However, in both cases, with a simple single mixed refrigerant (SMR) liquefaction technology, the facility can be cost-efficient, faster to build and easier to operate.
Several innovative, low-cost and game-changing FLNG configurations have been conceived based on the space-efficient and simple-to-operate liquefaction technology – PRICO® SMR – for both offshore and nearshore applications. The simplicity, flexibility and scalability of this process allow a wide range of liquefaction capacities in a unique single- or multiple-train configuration. These configurations include new-built carriers and conversion of existing LNG and bulk carriers.
This paper covers the development of innovative FLNG solutions, including all critical systems and other aspects of the technology and their impacts on the configuration of these solutions, offshore or nearshore.
Numerical Maximization of the Secondary Polymer Flooding Value in a Mature, Offshore, Heavy Oil Reservoir
Authors: Mogollón J. L. , Tillero E. , Gutiérrez I. , Luján L. 
Published: April 2016

Successfully implementing polymer flooding and maximizing benefits requires selecting best options of variables such as polymer concentration and slug, and number and location of new wells. Option-decisions combined generate thousands of scenarios. Therefore, even using smart algorithm optimizers to efficiently find the maximum of a business objective mathematical function can be a very time-consuming process.
The objective of this article is to demonstrate a methodology to improve the chances of finding the maximum net present value (NPV) solution for planning an offshore polymer-flooding; this includes finding, for example, the minimum injection volume to more easily offshore operations.
The reservoir and economy models included here were automatically coupled with software that encloses a smart numerical algorithm for searching complex maximum/minimum functions. The options of the previously mentioned decision variables were selected to maximize the NPV of the inverted five-spot polymer-flooding project under constrained rig availability. The process was conducted in three stages:
Stage 1: potential value estimation
Stage 2: narrowing options through deterministic numerical simulation
Stage 3: A) numerical optimization of all decision variable options except the drilling sequence; B) numerical optimization of the drilling sequence

A total of 379 scenarios were numerically forecasted in just a few months. The best scenario showed three times the NPV of the nonflooding case. Compared to the reference water-flooding scenario (i.e., all the same options but with the fluid injected), the NPV was 1.3 times greater, the water-oil ratio (WOR) was 0.45 times lower, and Np was 1.25 times greater. Unobvious scenarios, such as reducing the yearly drilling rig availability but extending drilling by four years, were revealed. A comparison of the working time for Stage 2 with Stages 3A and 3B showed that the numerical optimization is six times faster per scenario generated.
This study demonstrates that the use of numerical algorithms of polymer flooding yields a significant incremental value over traditional deterministic simulations in a much shorter time frame and with fewer costs compared to previous steps related to building a reservoir model. It is expected to be applicable to all types of enhanced oil recovery (EOR) processes.
New Squall Wind Criteria for the Gulf of Mexico
Authors: Jeans G. , Cooper C. , Yetsko C. 
Published: April 2016

Abstract
This paper presents new squall wind criteria for the Gulf of Mexico. Squalls are responsible for sudden rapid increases in wind speed and changes in wind direction, which can have a major impact upon vessels and offshore structures. These need to be quantified for operability assessments and structural design. Extreme squall wind gusts are estimated from many years of measured hourly maximum wind gusts, from the Continuous Winds dataset of the US National Data Buoy Center (NDBC) archive. Quality control was required to remove some anomalous high gust values. The new analysis supports key findings from a preliminary analysis first published in 2014, with a considerable reduction in uncertainty. The new 10-year return period estimates of squall winds (5 second gust at 10m elevation) are approximately 32 m/s. These exceed the corresponding value specified for a winter storm within API 2MET (27.7m/s). This has potential implications for operating criteria in the Gulf of Mexico.
Comparison of Riser Fatigue Methodologies Based on Measured Motion Data
Authors: Mercan B. , Chandra Y. , Maheshwari H. , Campbell M. 
Published: April 2016

Abstract
In-situ riser structural monitoring has been used by a number of operators and drilling contractors to support drilling operations. The measurements have been used to understand the level of accuracy present in the up-front fatigue analysis and to confirm the integrity of the drilling systems, especially during extreme environmental events. However, the field data analysis requires detailed understanding of drilling riser modeling, loading conditions, operations, sensor characteristics and signal processing. Several methods have been developed to calculate stresses and fatigue damages in the riser using measured motion data. Careful selection of the analysis approach will determine the system configuration and validity of the measured results.
Mode shape matching has been widely used for the data analysis where riser response is dominated by Vortex Induced Vibration (VIV). Another riser fatigue method has been recently developed and is based on analytical transfer functions used to convert measured accelerations into curvature. Another method considers FEA-based transfer functions. Some of these methods perform fatigue calculations in time domain while some others in frequency domain.
Each method exhibits benefits and limitations depending on the characteristics of the measured riser response. Selecting the most appropriate fatigue methodology depends on the riser response and instrumentation system design.
In this paper, three fundamentally different riser fatigue methods utilizing measured motion data are described and compared with each other. The advantages and disadvantages of each approach are evaluated and recommendations are provided for when each method should be considered.
A Review of Coupling Approaches for the Dynamic Analysis of Bottom-Supported Offshore Wind Turbines
Authors: Manuel Lance , Sahasakkul Watsamon , Nguyen Hieu , Sari Ali 
Published: April 2016

Abstract
Offshore wind turbines are designed and analyzed using simulation tools (computer codes) capable of predicting the coupled dynamic loads and responses of integrated turbine and support structure systems. A partially coupled analysis using load exchange is often desirable to meet intellectual property rights interests of disparate design teams and developers of the various components. Of interest is the assessment of the validity of such partially coupled analysis approaches for offshore wind turbine systems with various types of foundations. Computer-aided engineering (CAE) tools—such as the National Renewable Energy Laboratory's (NREL's) open-source FAST software and commercial structural analysis and design software—can use partial or full coupling to simulate loads and motions for utility-scale offshore wind turbines with various support structures. In partially coupled analysis, computed tower-base loads from the aeroelastic simulation tool are fed to structural response simulation tool at a suitable interface; required hydrodynamic and wind loads are introduced as needed on the exposed substructure. In fully coupled analysis, the transfer is two-way—i.e., forces at the interface are intrinsically exchanged between the aeroelastic and structural tools at each time step. It is desirable to compare the loads between alternative partially coupled models that are calibrated against a reference fully coupled case. This paper proposes a framework for the assessment of the validity of partially coupled models in the prediction of short-term and long-term loads and motions associated with large utility-scale bottom-supported offshore wind turbines that might be deployed in offshore wind power development.
Using LIDAR Based Control to Reduce Loads on Floating Wind Turbines and Boost Performance
Authors: Guillemin Fabrice , di Domenico Domenico , Sabiron Guillaume , Averbuch Daniel 
Published: April 2016

Abstract
Offshore wind turbines are being developed worldwide as a large scale source of renewable electricity. However, to accelerate and secure the development in the long term of offshore wind, there is a need to reduce the cost of electricity. To achieve this, wind turbine manufacturers are developing larger size wind turbines, which allow foundation, installation and balance of plant cost reduction. Developing larger wind turbines brings new design challenges, as offshore wind turbines are subject to severe loading resulting mostly from wind speed variation, incoming gusts, and wave loading.
The paper presents current developments aiming at reducing loading experienced by offshore wind turbines using advanced control strategies and LiDAR based long-distance wind measurements.
In order to mitigate the wind loading, modern wind turbines indeed rely on control systems that define optimal blade pitch positions, in order to reduce the load variation, while optimizing produced electricity. However, most control systems are only based on a feedback from the turbine sensors information, and are therefore limited.
In order to overcome this limitation, current developments are being performed to take advantage of additional sensors named LiDAR (Light Detection And Ranging), that can be mounted on the nacelle of wind turbines, and provide long distance wind speed measurements ahead of the wind turbines. Lidars thus provide wind speed measurements at a distance of a few hundred meters, which allow a sufficient reaction time to control the wind turbines.
This paper presents new nonlinear strategies that can be used for bottom founded and floating wind turbines, using nacelle-based lidar measurement. Examples are given to highlight the benefits of such strategies, on the wind turbines blades and tower fatigue design. Specific strategies are proposed for floating wind applications and exemplified in the paper, showing a significant load reduction for fatigue and extreme situations. Additionally, production increase can also be obtained. Therefore, these two benefits provide an important contribution to cost reduction of offshore turbines.
A Perspective on the Development of a Basis of Design for Evaluation of Seismically-Induced Offshore Geohazards
Authors: Sancio R. , Al-Sharif M. 
Published: April 2016

AbstractAlthough numerous studies have been conducted, a recommended practice for incorporation of earthquake loading into the geotechnical design considerations for subsea structures such as wells, manifolds, and PLETs, and pipelines is not consistent. Industry guidance provided in ISO 19901-2 and the more recent API adoption, RP2EQ, provide performance-based recommendations for selection of a two-level seismic design. At the first level the structure is designed to retain its full capacity (and likely its operability) at ground motions with a return period typically under 200 years that depends on the exposure level of the structure. At the second level ground motions that are less likely to occur over the lifetime of the structure are used to ensure global failure is avoided. The guidance, however, was written specifically for fixed steel structures and fixed concrete structures for which exposure incorporates first and foremost life safety, with secondary consideration for environmental exposures caused by system failures, and economic losses to the owners and operator. Subsea field architectures that only include subsea gathering and distribution systems and structures present no exposure to human life, therefore the decision to incorporate earthquake loads should be done with consideration given to mitigation and prevention of environmental releases and tolerable levels of damage. The latter include consideration of: (i) costs associated with production down time and schedule; and (ii) costs for replacement and rehabilitation of damaged facilities.In this paper we provide: (1) a discussion on existing industry guidance for reliability-based design; (2) reliability-based process for incorporating triggering of seismically-induced soil liquefaction and its consequences into foundation design, and design criteria in a moderately seismic environment with a seabed architecture that only includes manifolds, PLETs, pipelines, umbilicals, and associated structures; and (3) a reliability-based process for evaluation of seismically-induced stability of slopes and its incorporation in the evaluation of pipeline routes.