bluuebunny/crossref_metadata_2025_split huggingface dataset:
Value Creation and Cost Management by Use of the New ISO 15663 Life Cycle Costing Standard
Authors: Willmann Endre , Østebø Runar , Montalvao Eduardo H. R. 
Published: August 2021

Abstract
The new edition of the ISO 15663 standard has been developed during the recent years and will strengthen the industry cost management for business value creation. This paper shows how such standardization can be used to further enhance and promote adoption of a common and consistent approach to life cycle costing in the offshore oil and gas industry.
The new ISO 15663 edition maintains key principles from previous editions, but does also introduce an improved and revised management methodology for application of life cycle costing. The purpose is to provide decision support for selecting between alternative options (e.g., projects, operational and technical subject matters) across life cycle phases, also aligned with overall corporate business objectives such as HSE and sustainability. It also provides the means of identifying cost drivers and a framework for value optimization over the entire life of an asset.
The international standard is providing an essential set of normative requirements on how to implement and apply the life cycle costing methodology and the decision criteria, supported by an exhaustive part of recommended practices. This includes the identification of common and specific contractual considerations for operators, contractors and vendors (e.g., complementary metrics besides expenditure, such as systems availability guarantee and risk-sharing clauses). It also includes the application in the life cycle phases of an asset, the techniques and data input, examples of application, and assessment and lessons learnt. Capital expenditure (CAPEX), operating expenditure (OPEX), revenue and lost revenue (LOSTREV) factors are addressed. The standard includes an unambiguous definition of the economic objectives of a project and application of the same business criteria when making major engineering decisions. The life cycle costing methodology is applicable to all asset decisions in any life cycle phase, but should be applied only when expected to add value for decision-support. The required extent of planning and management of the appropriate life cycle costing is depending on the magnitude of the costs involved, the potential value that can be created and the life cycle phase.
This paper demonstrates how the new ISO 15663 can be utilized by providing new examples of life cycle costing, to give all participants in the process — oil and gas operators, contractors and vendors — an up-to-date and streamlined set of requirements and guidance, encouraging a fit for purpose application. The paper does also present unique key economic evaluation measures such as life cycle cost (LCC) and net present value (NPV).
New Downhole Sand Entry Detection Technology Leads Directly to Successful Remedial Work and Additional Oil Production
Authors: Agrawal Gaurav , Eissa Moustafa , Singh Kamaljeet , Dutta Shaktim , Kumar Apoorva , Okeke Uche 
Published: August 2021

Abstract
The consequences of sand production are often disadvantageous to the short and long-term productivity of the well. Although some wells routinely experience controllable sand production, these are the exception rather than the rule. Sand production and its management over the life of the well is not an attractive situation but is often essential to extract the resource. Knowing the root cause behind sand inflow in a well and the possible results can inform an appropriate strategy to safely extract as much of the resource as possible.
The sands in such reservoir units often have high permeability and are mechanically weak and prone to sand production. The producing wells are often completed with gravel-packed completions for efficient sand control. Most of the wells have multi-zone completions for better productivity but this further complicates reservoir characterization.
This paper describes the first use of downhole sand impact detection technology in such fields. The sand detection technology integrates the fully digitized high-resolution acquisition with signal processing and interpretation algorithm to enhance the sand particle detections as small as 0.1 mm in diameter and up to 1,500 impacts per second. The tool is designed to immune the sensors from any background noise and gas/liquid jetting effect.
A combination of production logging tools (PLT) and the sand impact detection tool, was used to understand four phase zonal contributions (gas, oil, water and sand) and pinpoint sand entry in these cases. Results exceeded expectations and the ability for the sand detection tool to accurately detect the point of sand entry enabled immediate intervention to eliminate sand production in these case studies. One of them also resulted in increased production of 7.4kb/d oil without any sand flow and with greatly reduced gas-oil ratio as compared to pre-intervention production.
The work clearly demonstrates the practical and effective use of downhole sand impact detection with new sand detection technology to identify and isolate sand production in wells. The innovative tool design makes it feasible to detect even small sand particles in adverse wellbore conditions and varied production rates, thus adding a detection of the fourth phase in an otherwise three phase production log.
Propulsion Solution for Icebreaking LNG Carriers
Authors: Hanninen Samuli , Barisic Matko , Heideman Torsten , Goldon Krzysztof , Viherialehto Sampo , Maattanen Pirjo 
Published: August 2021

Abstract
Since 2007 the traffic volumes in the arctic seas have substantially increased, especially in the North-East Passage following the development of major oil and gas projects. In development of icebreaking LNG tankers the selection of propulsion system is playing a major role determining the vessel performance, safety and icebreaking capability. Recent success of YAMAL LNG project has led to accelerated development of new arctic LNG projects, such as Arctic LNG2. This paper will introduce some outstanding operational results from the revolutionary icebreaking LNG Carriers with modern azimuth propulsion system.
This paper describes the methodology to use remote diagnostics systems (RDS) onboard ice-going LNG carriers to continually record, consolidate, upload, and analyze ice-breaking propulsion performance. We will further describe how vessel operational experience and RDS data can be used in development of icebreaking LNGC propulsion design and product development.
The special focus in this paper will be given on propulsion system of large Arctic LNGC equipped with 3 × 15 000 kW azimuth thruster units. These propulsion devices help ship owners to access opportunities in the Arctic areas by providing safe and reliable operation in the region. Paper will highlight some of the key findings from the ship machinery data collected with RDS (Remote Diagnostic system) and further analyzed by engineer specialist in view of ice loading on machinery system and components.
Podded propulsion solution has played major role on Arctic ship projects, making these challenging projects technically and economically feasible. We will present latest findings and unique results from Arctic LNG carriers, which is valuable information in development of future Arctic oil and gas transportation in the Northern hemisphere.
Significant Performance Improvement with MPD in HPHT Narrow Drilling Window Campaign in the North Sea
Authors: Kamal Babar , Saboor Abdul , MacFarlane Graeme , Kernche Frank 
Published: August 2021

Abstract
Significant depletion in reservoir pressure, huge uncertainties in pore and fracture pressure, high overburden pressure on top of reservoir, Narrow Mud Weight Window (NMWW) and Partial/Total losses whilst entering the reservoir made these HPHT (High Pressure High Temperature) wells conventionally un-drillable. Due to these substantial challenges these wells were considered not only costly but also carry a high probability of failure to reach well TD (Total Depth). MPD (Managed Pressure Drilling) is a safer and more effective drilling technique as compared to conventional drilling, especially in wells with NMWW and downhole hazards. The precise determination and dynamic downhole pressure management was imperative to complete these wells without well control incidents. The Constant Bottom Hole Pressure (CBHP) variant in combination of automated MPD system was deployed with a mud weight statically underbalanced while dynamically managed above formation pore pressure to minimize the overbalance across the open hole. MPD enabled the operator to efficiently navigate Equivalent Circulation Density (ECD) through the pore and fracture pressure window, allowed significant improvements throughout the entire campaign.
This paper discusses the challenges faced during the last three wells drilled in the campaign which includes equipment issues, commissioning delays, losses whilst drilling, Managed Pressure Cementing (MPC), 7" drill-in-liner and plugged/blocked lines due to weather and mud conditions. The paper describes HPHT infill drilling experience, specific techniques, practices as well as lessons learned from each well during the campaign were implemented to address challenges and to improve performance. The MPD system commissioning was optimized by repositioning the lines which saved significant critical rig time. The blowdown points were added on the lines that were not operational continuously therefore a procedure was developed for flushing to avoid plugging. Optimized drilling strategy was also developed where MW was further reduced to avoid losses as observed in previous wells and CBHP was maintained by manipulating Surface Back Pressure (SBP) from surface.
This paper also discusses continuous improvements /upgrades in MPD operating software which assisted the operator in accurate monitoring of flow, SBP and BH-ECD to save significant rig cost in terms of invisible Non-Productive Time (NPT). MPD is a drilling enabler and performance enhancer which saved 80 days of Authorization for Expenditure (AFE) on this challenging HPHT campaign.
Innovative Energy Storage Concept for Saipem Offshore Wind2Sub™ Application
Authors: La Sorda Enrico , Pucci Francesco , Mauries Benjamin , Storheim Birgitte , Arcangeletti Giorgio 
Published: August 2021

Abstract
Reducing CO2 emissions is becoming one of the core targets for countries after the Paris agreement, which sets out a global framework to avoid dangerous climate change by limiting global warming to below 2°C and pursuing efforts to limit it to 1.5°C. To meet this objective also oil and gas operators have started to engage in an important effort to reduce the CO2 emissions in their plants and facilities.
From this perspective Saipem developed its Wind2Sub, a Wind Power for Long Subsea Tie-Back (LSSTB) concept, where its own pendular floating foundation solution, namely Hexafloat, can host a wind turbine generator (WTG), all the utilities needed for subsea field development and operation (power distribution, chemical storage and injection, control system) and a back-up energy system to compensate the intermittent production due to wind persistence, currently a diesel generator (DG).
The present paper will explore new solutions to ensure the continuity of the energy supply from Saipem Wins2Sub, based on green technologies. This may be done by collecting the generated surplus energy from a renewable energy system, in this case from WTG to a topside or subsea power storage. By adopting an Energy Storage System (ESS), it will be possible to use this energy when production from wind is low or null. This concept will replace the diesel generators, or any carbon fuel, so that the whole system will become green self-sustaining, as an energy island, without CO2 emissions.
The activities performed during the concept development are articulated through the following steps: a selection of two typical oil field scenarios where Wind2Sub solution can be applicable; screening of the current technologies to store energy and a selection of those viable to the two selected scenarios; wind conditions and WTG power analysis with estimation of the amount of the energy to be stored; preliminary design of the ESS; preliminary cost estimation.
The study was carried out by using a digital tool developed by Moss Maritime in the context of a Proof of Concept based on Floating energy storage. The tool allows to evaluate the feasibility of a solution through modellization of different renewable energy scenarios, demand profiles, simulation of operation, pre-sizing of the systems and cost estimation (LCOE, LCOS, LCOH).
The ESS combined with Saipem Wind2Sub will be described more thoroughly in the present paper through the explanation of the results achieved within the case studies.
Autonomous Inflow Control Valve Multiphase Flow Performance for Light Oil
Authors: Taghavi Soheila , Gisholt Einar , Aakre Haavard , Håland Stian , Langaas Kåre 
Published: August 2021

Abstract
Early water and/or gas breakthrough is one of the main challenges in oil production which results in inefficient oil recovery. Existing mature wells must stop the production and shut down due to high gas oil ratio (GOR) and/or water cut (WC) although considerable amounts of oil still present along the reservoir. It is important to develop technologies that can increase oil production and recovery for marginal, mature, and challenging oil reservoirs. In most fields the drainage mechanism is pressure support from gas and/or water and the multiphase flow performance is particularly important. Autonomous Inflow Control Valve (AICV) can delay the onset of breakthrough by balancing the inflow along the horizontal section and control or shut off completely the unwanted fluid production when the breakthrough occurs. The AICV was tested in a world-leading full-scale multiphase flow loop located in Porsgrunn, Norway. Tests were performed with realistic reservoir conditions, i.e. reservoir pressure and temperature, crude oil, formation water and hydrocarbon gas at various gas oil ratio and water cut in addition to single phase performances. A summary of the flow loop, test conditions, the operating procedures, and test results are presented. In addition, how to represent the well with AICVs in a standard reservoir simulation model are discussed. The AICV flow performance curves for both single phase and multiphase flow are presented, discussed, and compared to conventional Inflow Control Device (ICD) performance. The test results demonstrate that the AICV flow performance is significantly better than conventional ICD. The AICV impact on a simplified model of a thin oil rim reservoir is shown and modelling limitations are discussed.
The simulation results along with the experimental results demonstrated considerable benefit of deploying AICV in this thin oil rim reservoir. Furthermore, this paper describes a novel approach towards the application of testing the AICV for use within light oil completion designs and how the AICV flow performance results can be utilized in marginal, mature, and other challenging oil reservoirs.
Low-Temperature Diverter Improves Operational Efficiency and Well Performance in Offshore Application
Authors: Vidma Konstantin , Bremner Samuel Edward , Ziyat Sophia , Choo Daryl , Abivin Patrice , Yusuf Temiloluwa Iyenoma 
Published: August 2021

Abstract
Near-wellbore diversion during acid fracturing or matrix acidizing is widely used to improve reservoir coverage and to save time spent on zonal isolation. It is particularly useful in offshore operations where efficiency is crucial. Diversion is typically achieved by dynamic placement of degradable solid particulates into perforations, wormholes, and/or fractures to divert the treatment fluid to understimulated zones. The diverting material must maintain integrity and mechanical strength during the operation before degrading at the downhole temperature in the presence of stimulation fluids. Whereas currently used materials work very well in a wide temperature range, at temperatures below 140°F (60°C), finding an appropriate diverting material that balances the trade-offs between surface shelf-life, stability during treatment, and fast downhole degradation is a challenge. This paper presents a novel low-temperature diverter that pushes the degradable diverter temperature limit down to 70°F (21°C). The new material was deployed in a matrix acidizing job performed on an injector well in the North Sea. Field deployment was preceded by an extensive laboratory testing program to verify diversion efficiency and acceptable degradation.
The novel diverter was deployed in a restimulation treatment of a 10-year-old injection well where BHT was reduced to 70°F (21°C) due to long term injection of cold water. An acidizing treatment was designed to incorporate 4 diversion pills of the novel diversion material. All diversion pills were placed without extra operational time or operational issues. All four pills showed an instant pressure response of more than 250 psi as well as a sustained pressure increase of more than 100 psi, providing an indication of effective fluid diversion. The well was switched to injection mode less than 36 hours after the end of treatment without any flowback, providing a tremendous gain in operational efficiency. The post-treatment injection rate increased by 150% for several days, demonstrating significant and fast diverter degradation, despite the low temperature. The injection rate later stabilized at more than twice the pretreatment injectivity. The results demonstrate the viability of the novel low-temperature diverter in wells with BHT of 70 to 140°F (21 – 60 °C).
Novel Experimental Method to Determine the Performance of Vacuum Insulated Tubing VIT for Deepwater Applications
Authors: Ceyhan I. , Vasantharajan S. , Suryanarayana P. V. , Sathuvalli U. B. , Helou A. , Barde P. 
Published: August 2021

Abstract
Vacuum insulated tubing (VIT) is a specialized tubular designed to minimize heat loss from production or injection fluids to the environment in oil, gas and geothermal wells. VIT strings are used in deepwater wells for flow assurance or to mitigate annular pressure buildup. VIT use requires accurate knowledge of its insulating performance. Although VIT performance can be estimated from analytical tools, such as finite element analysis (FEA), an experimental approach provides a more direct measurement and can be used to validate analytical tools. We have developed a new experimental method to address this need.
In this method, one or two VIT joints are placed in an ice-water bath. A precisely measured flow of heated air flows inside the VIT. The temperature change of the flowing air is measured between the inlet and outlet of the VIT test specimen. The insulating performance of the VIT is then calculated from this temperature difference using heat exchanger theory with effectiveness-number of transfer units (&#ξ03B5;-NTU) approach. A proportional-integral-derivative (PID) controller is used to control the air temperature at the VIT inlet by regulating power to the heater.
This paper illustrates the data reduction method and uncertainty analysis using sample test data. The method allows for rapid measurement of VIT performance at many different temperatures, with the air flow rate being used to optimize the test sensitivity and to reduce experimental uncertainty. As currently designed, the apparatus is able to test single- and double-joint VITs with effective body conductivities between 0.002-0.1 W/m/°C (0.001-0.06 Btu/hr/ft/°F) and temperatures up to 400°C (750°F); however, the design allows the apparatus to be modified easily for higher or lower conductivities.
Although designed for VIT, this method may be applied to other types of tubulars. Currently, there is no widely accepted standard method for experimental testing of VIT performance, and it is hoped that this new method may evolve to an industry standard.
Quality Assurance Framework to Enable Additive Manufacturing Based Digital Warehousing for Oil and Gas Industry
Authors: Kandukuri Sastry Yagnanna , Moe Ole-Bjørn Ellingsen 
Published: August 2021

Abstract
Additive manufacturing (AM) makes it possible to produce parts on demand, close to operations, with significantly reduced lead times compared to conventional manufacturing. However, without standardization or guidelines, additively manufactured parts could raise the risk of unexpected or premature failures due to inherent variation of mechanical and metallurgical properties associated with this new technology. This is especially true when the reduced lead time is the desired advantage, where speed may be prioritized over quality. A standardised framework is proposed to free up value locked in physical warehouse inventory and reduce inventory management cost through digital warehousing in a safe and cost-efficient way. Through a joint industry project, with participating companies throughout the entire AM value chain, we propose an assurance framework that answers questions such as: can the digital drawing be available when needed? Can the parts be made ‘first time’ right when needed? Can it be made with the same quality at another location next time? Which party is responsible for the different stages? What requirements should be in place for the companies who wish to manufacture on demand?
The digital warehouse assurance framework discussed in this work demonstrates that digital warehousing powered by AM could potentially shorten lead times for sourcing parts and reduce the need for costly storage, maintenance and coordination of spare parts that are rarely used. We also discuss the different variants of digital warehousing we may see, and the roles and responsibilities various digital warehouse stakeholders have for facilitating unambiguous communication.
AM is already disrupting supply chains in many other industries, but it is in its infancy in the oil & gas, offshore and maritime sectors as they ponder challenges with intellectual property (IP) and usage rights for original equipment manufacturers (OEM) designs, standardization of technology interfaces and the lack of knowledge and trust of the technology. The digital warehouse quality assurance framework proposed and discussed in this work is unique and has potential to not only accelerate adoption of AM in oil & gas and offshore sectors, but also contribute to a significant reduction of emissions, including greenhouse gases.
Facing the Challenges of Implementing Systems Engineering
Authors: Bullion James Anthony 
Published: August 2021

Abstract
The objective of this paper is to introduce and address the programmatic and technical challenges associated with the implementation of systems engineering (SE) at the enterprise level in the oil and gas environment. However, the lessons applied here could be tailored and applied to the project level. Currently, there is a strong movement towards a digital transformation of the industry, from exploration of new fields to the revitalization of more mature fields. A systems engineering environment is a prerequisite for the conversion and implementation of Digitalization Transformation. This paper will outline and address the risks and rewards of the partial to full implementation of the principles and methodologies of systems engineering across the lifecycle of a project. The ideas and methods presented here are what should follow once a decision to implement SE into an organization has been made. It assumes that the reader has reviewed the costs, benefits, and results of a digital engineering approach. The scope of this paper will address the technical as well as the organizational challenges that the initiator should be prepared to address in order to be successful.