bluuebunny/crossref_metadata_2025_split huggingface dataset:
How is Multiple-Point Geostatistics of Lithofacies Modeling Assisting for Fast History Matching? A Case Study from a Sand-Rich Fluvial Depositional Environment of Zubair Formation in South Rumaila Oil Field
Authors: Al-Mudhafar Watheq J. 
Published: April 2018

AbstractModeling accurate lithofacies and petrophysical properties is a crucial step in the reservoir characterization as it affects reservoir heterogeneity, fluid flow modeling, and history matching, especially in complex geological structures. In this paper, the multiple-point facies geostatistics (MPFG) and sequential gaussian simulation were integrated as an efficient workflow for lithofacies and petrophysical property modeling of a fluvial sand-rich depositional environment of Zubair formation in South Rumaila oil field, Southern Iraq. The lithofacies features of the upper sandstone member has three main lithotypes derived from the core data analysis of 20 wells: sand, shaly sand, and shale.In the MPFG, the surface map of the fluvial depositional system of the upper sandstone reservoir in Zubair formation was created through a 2D user-defined training image. The training image body and channels were pointed to the three aforementioned lithofacies as an alternative to the variogram to create the 3D facies system. Then, the surface map was sampled and trained by neural networks to create the discrete template of 3D facies distribution pattern into the 3D grid construction. The resulted pattern represents a numerical geomodel that captures all the features of the fluvial depositional environment of the reservoir, which then was adopted for 3D lithofacies modeling.The resulting MPFG-lithofacies model reflected a more reasonable facies architecture than the sequential indicator simulation by preserving the fluvial features of the geosystem. Many realizations were generated and cross-validated to determine the most appropriate lithofacies model, which was considered later for the permeability and porosity modeling by the sequential gaussian simulation. To attain history matching, the resulting MPFG and petrophysical model was upscaled and incorporated into the compositional reservoir flow simulation for history matching. A near-perfect and fast history matching with the least mismatch was obtained with respect to observed and calculated cumulative and rates of oil production and water injection for the entire field in addition to all producers and injectors within the whole production history. The results reflect how is efficient considering multiple-point statistics to reconstruct the complex geological features to capture reservoir heterogeneity and achieve fast history matching.
Redefining Capital Investment: A Steady Hand in an Unsteady Time
Authors: Abughazaleh Waleed 
Published: April 2018

Over 57% of Oil & Gas mega-projects exceed original budget and delivery timeline and this figure grows to over 80% for mega-projects internationally. This is detrimental to capital investment returns, especially when posed against a backdrop of weak oil prices. Integrated Oil Companies (IOCs), National Oil Companies (NOCs), and investors looking to maintain or gain a strong position in the oil and gas market are silently struggling to properly assess and secure viable strategies for capital investments. Even in a world where oil price fluctuations can be mitigated, returns are relative to each company's evaluation of capital projects and execution strategies. Unfortunately, current capital project selection methodologies are unfit to account for such wide discrepancies in performance outcome.
At the corporate level, each entity develops a framework for appraising and assessing the economic viability of its capital investment opportunities. Business cases and investment analyses employ variations of Net Present Value analysis (NPV) and Internal Rate of Return (IRR), modified to create company specific metrics that are meaningful for selection of capital projects. Yet, the prevalent overruns, in budgets and delivery timelines, translate directly into significant reduction of capital investment capability, and erode returns. These negative results are often not realized until the capital is irreversibly committed.
Past sprints of high oil prices provided a forgivingly large margin of return that made profitability certain. Moreover, the long-term nature of oil projects obscures the impact of cost overruns. However, extended low oil price environments, such as the current state, expose critical gaps in existing capital management methodologies within project driven entities. A more rigorous investment study is required for future capital allocations to ensure profitability, and in some cases, solvency.
In this paper, I present a conceptual framework for capital allocation management. This new framework, Advanced Risk and Capital Allocation Management (ARCAM), aims to synchronize risk, strategy, and capital decision modeling to ultimately give better visibility of future performance of capital investment opportunities. For the purpose of this paper, the investment decision makers are the IOCs, NOCs and oil service companies.
I will begin by referencing challenges highlighted by executive management in earning calls of top oil corporations and jointly looking at performance data of mega-projects in recent years. After taking into account the impact of low oil price environment, we will explore how applications of ARCAM framework can be leveraged to better assess the financial viability of capital investments within the oil and gas sector.
The Impact of Digitalization on Offshore Operations
Authors: Sylthe Olav , Brewer Thornton 
Published: April 2018

Most of today's digital initiatives in oil and gas are incremental rather than disruptive. Some companies are taking a step forward to make improvements in technical or operational capabilities, but many are not fully embracing the power digitalization can provide. Numerous benefits such as increased cost savings and significant improvements in collaboration, productivity, maintenance and revenue have been realized through digitalization…if only more offshore operators would take the technological plunge.
Online collaboration technologies provide offshore engineers the ability to digitize workflow and planning processes, optimize decisions between experts, disciplines and companies involved in the life of field perspective, and visually identify operational activities and maintenance events once projects are online. Through digitalization, all offshore field projects – assets and activities – are: easily understandable through online 2D/3D visualizations; rapidly created or replicated using existing field layouts with a 3D asset library; immediately monitored and reporting to real-time operating levels; and getting an instant view of the cost consequences due to a required action or change to a field. Offshore operations would dramatically change upon oil and gas companies embracing and upgrading their digital capabilities, thus improving the way they collaborate with and connect new data insights to their operating models.
The novelty for offshore engineers is that digital collaboration tools are easy to integrate and train the next generation of employees to, and capable of accelerating project timelines by up to 80%, especially during the early concept and FEED phases. These time savings can drive cost savings as high as 70% across a project's lifecycle. The benefits are undeniable when this technology is implemented across the oil and gas industry…regardless of current oil prices.
CFD Analysis of Entrapped Water Response of FPSO/FLNG Turret
Authors: Yu Kai , Hsieh Yvonne , Ge Zhongfu , Yu Qing 
Published: April 2018

Abstract
In recent years, large diameter internal turret systems are increasingly becoming a viable solution for large FPSOs and FLNGs in harsh environmental conditions, because of higher vertical load capacity and flexibility in the riser number. The large volume of water in the moonpool introduces unique design challenges in extreme operating conditions, due to complex interactions between the water and the turret structure. The water trapped inside the moonpool exerts considerable dynamic loads on the turret and moonpool structures. These loads are combined with other environmental loadings and need to be considered in the design of the system.
In the present work, computational fluid dynamics (CFD) models were created for simulating complex entrapped water dynamics in a generic large turret design. The CFD model in this study used fully 3-D Reynolds-Averaged Navier-Stokes (RANS) equations and the k-ω SST turbulence model. Additionally, a multiphase flow model, using the volume of fluid (VOF) method, captured the free-surface. The analysis matrix included cases with forced free surface motions, vessel forced motions and vessel responses to regular and irregular waves.
The CFD simulation started with grid and time step sensitivity studies for an open moonpool. The CFD model was further validated with free decay cases by comparing the results with empirical estimates. After that, a chain table and a turret system were added into the model to perform free decay cases and forced motion cases. That CFD model was also assessed with the vessel motions in regular and irregular waves. Simulation results revealed sloshing and piston modes and natural decay rates in the moonpool, as well as temporal and frequency characteristics of water motion in response to wave forcing.
The CFD simulations clearly captured the effects of the moonpool, the chain table and the turret structures on the dynamics of entrapped water. The simulation results offered valuable insights into the flow patterns of entrapped water in the moonpool as well as the resultant dynamic loads, which are crucial to the moonpool and turret design.
Flow Assurance Engineering in Deepwater Offshore - Past, Present, and Future
Authors: Bomba John , Chin Doreen , Kak Ashutosh , Meng Weihong 
Published: April 2018

Abstract
The objective of this paper is to provide a review of the evolution of the flow assurance discipline over the years as it applies to the design of gathering and export pipeline systems. In the early days, pipeline design was essentially a job for one engineer when pipelines were on land or in shallow water, not in a new geological province, flowing temperatures / pressures were not abnormal, and had no multi-phase flow or contaminants.
This paper will identify events or circumstances that affected how "~Pipeline Hydraulics" were designed. Flow Assurance Engineering has evolved from two fundamental pillars – thermo-hydraulic analysis of fluid flow in production systems, and production chemistry.
Today, flow assurance engineers in a project not only provide predictions, but also prevention strategies, and remediation methods for: Fluid characteristicsFlow hydraulics and thermal behaviorsPerformance of the production systemGuidance of operation strategiesIdentification and management of solid deposition issues: hydratesparaffins (waxes)asphaltenesscales, etc.
They interface with multiple disciplines involved with the project, including subsurface, pipeline and risers, subsea hardware, topsides process facilities, chemical vendors, the fluid laboratory, etc.
Beginning in the late 1940s, pipelines began transporting hydrocarbons over long distances onshore (conversion of the Big Inch Crude and Little Inch product pipelines to natural gas service for example) when unforeseen flow problems began to occur. Exploration gradually moved to nearshore drilling, and finally, to shallow water. Additional flow problems increased in complexity and magnitude.
To track how these increasingly complex flow problems affected pipeline design, this paper presents: The evolution of Flow Assurance from simple hydraulics calculations to a well-defined engineering disciplineThe critical responsibilities in current deepwater development - Greenfield and Brownfield projectsThe re-shaping of Flow Assurance Engineering by digital revolution and big data technologiesThe evolution of the discipline applying new technologies to unlock new reserves with longer, deeper tiebacks
ISO Standards to Enable Reliable, Safe and Cost-Effective Technology Development, Project Execution and Operational Excellence
Authors: Østebø R. , Selvik J. T. , Naegeli G. , Ciliberti T. 
Published: April 2018

This paper addresses the current oil & gas industry need for awareness and how to accelerate use of international standardization efforts, with focus on multi-disciplinary ISO standards and business governance. Qualified compliant use of ISO standards can unlock necessary business value and is a means to achieve cost-efficiency, HSE objectives, and minimize climate impact. The user domain encompasses regulatory bodies, oil and gas companies, drilling companies, engineering companies, equipment manufacturers, research & consultancies.
The ISO/TC67 Working Group "Reliability engineering and technology" has responsibility for reliability and cost related ISO standards within the Petroleum, petrochemical and natural gas industries. The portfolio of the multi-disciplinary ISO standards is internationally acknowledged and has recently been updated by many new standards that the global user domain can benefit from to achieve cost reducing technologies. Reliability and cost is part of the equation in innovative technology development processes to enforce quality and minimize risk, and enable new technology meets overall business performance objectives.
This paper will give highlights of the following ISO standards and a roadmap for their application:
ISO 14224 - Collection and exchange of reliability and maintenance data for equipment
ISO 20815 - Production assurance and reliability management
ISO 19008 - Standard cost coding system to gas production and processing facilities
Company applications are presented to show examples in technology development, project development, and oil & gas field operations. Standards relation to digitalization of oil and gas industry will also be addressed, e g. how "reliability communication" between oil company and supplier can benefit from use of the latest ISO standard 14224. Contractual framing of reliability and Key Performance Indicators will also be presented.
This ISO standardization work is based on international expert team efforts by many countries, and in collaboration with IOGP. The work supports the ISO/TC67 Mission: "To create value-added standards for the oil and gas industry", and the ISO/TC67 Vision: "International standards used locally worldwide."
Campos Basin Technologies Yard: 40 Years of Lessons Learned
Authors: Roberto M. , Coutinho A. B. , Santos A. R. Dos 
Published: April 2018

Campos Basin, during the last 40 years, has been the stage where the technology development has played its main game in terms of pushing the offshore oil and gas production to overcome its challenges to go deeper and deeper in WDs never experienced before.
Incremental, innovative, enabler or even disruptive technologies, supported by a strong commitment to success and the capability and drive for field test new ideas have made such a difference.
Structured actions based on technology programs specific created for reaching defined targets, such as Petrobras Deep and Ultra Deep Water Technology Program named PROCAP, in its four sequential "versions" for over 28 years, resulted in two OTC Awards, in 92 and 2001, and helped Petrobras to achieve an important position worldwide in offshore production.
A focused projection of the future in terms of the next generation under development to overcame challenges related to revitalization of Campos Basin mature fields, such as life extension methodologies, heavy oil processing, oil and gas contaminants treatment, subsea boosting and separation systems, power distribution and transmission, that are part of Petrobras technologies "gold list" are being developed and they will be available in the next couple of years. Additionally, an internal program, named Subsea Operational Technologies, has been developed to promote a full integration among suppliers, R&D and operation teams to reduce OPEX and enhance oil and gas production in Campos Basin. Also, associated to that, a strong and efficient integrated operation control has promoted the required offshore field management drive and safety.
This paper will present a retrospective of the most significant Subsea system, Well Drilling and Completion, as well as Topsides technologies developed and deployed in the Campos Basin for more than 80 production systems in more than 30 oil and gas fields development.
Utilizing the High-Pressure Rheometer for Comparison of LDHI Effectiveness
Authors: Spratt Tony , Conrad Pete , Asheim Colton , McCarthy Ryan , Golczynski Tommy 
Published: April 2018

Abstract
A series of comparative tests have been performed between the autoclave and high-pressure rheometer to assess the capability of the high-pressure rheometer to replicate the results of the autoclave while utilizing smaller valumes and having increased sensitivity. A total of ten oils were used in the evaluation with an excellent correlation between the autoclave and rheometer. An overview of the results, the testing methodologies and equipment is contained within the paper to ensure the community can replicate the results.
Downscaling Global Wave Ensemble Forecasts With Machine Learning Techniques in Application to Billia Croo Test Site
Authors: Darbinyan David , Wang Michael , Buck Elaine 
Published: April 2018

Abstract
Accurate marine weather forecasts are essential for operational planning which could lead to significant cost savings on vessel, personnel, and equipment stand-by. There are many global forecasting products available on the market, providing free wind and wave forecasts on a global scale. However, the spatial resolutions are too coarse to fully resolve local effects. Several methods are available for forecast downscaling to represent local conditions: physical downscaling with high resolution mesoscale models, with global model providing the boundary conditions; bias correction of the global model forecast by an experienced forecaster with knowledge of local conditions; and statistical downscaling such as simple regressions or more sophisticated machine learning algorithms. The statistical downscaling approach allows fast, computationally inexpensive downscaling (as opposed to high resolution local model runs) without the need for continuous, operational support of a forecaster. Another advantage of this method is the possibility of constant improvement through continuous training as more data becomes available.
The European Marine Energy Centre's (EMEC) Billia Croo test site for wave energy converters (WEC) is situated at a location dominated by high seas. This makes the operations and maintenance planning for WECs a challenge, which accurate forecasts could help to partially resolve. Datawell Waverider buoys provide in-situ wave measurements in real-time, with data also being collected and stored. This dataset allows the implementation of machine learning algorithms to downscale the global marine forecast products. In this study, an attempt is made to downscale operational ocean wave ensemble forecasts from NOAA/NWS/NCEP model runs, with forecast lead times of +12, +24, +36, +48, +72, +96 and +120 hours. After preliminary machine learning model training, an on-line training algorithm is put in place to assess its efficiency and capacity to continuously improve the accuracy.
The utilisation of the wave ensemble forecasts as features in the machine learning model allows for consideration of the uncertainty of initial conditions of the forecast model run. A timeseries of in-situ observations in past hours are used as additional features, representing the preceding wave conditions.
Upgrade of Unbonded Flexible Pipe Design Capabilities in Pressure and Temperature
Authors: Bernard Gary , Bouche Pierre-Yves , Caicedo Juan , Chirat Mathieu , Deheeger Antoine 
Published: April 2018

Abstract
For decades, TechnipFMC has been providing unbonded flexible pipe technology with demonstrated capabilities up to 15,000 psi & 130°C (266°F). Lately, the need for high pressure high temperature production solutions has increased especially in the Gulf of Mexico. As limits are pushed further, new developments were initiated, continuously increasing the range of qualified products. This paper presents recent achievements extending the capabilities of flexible pipes technology up to 17,500 psi and 150°C (302°F).
While the test conditions of products are becoming more severe when targeting higher pressures and temperatures, the qualification process described in API RP 17B remain the main reference for qualification tests of unbonded flexible pipes.
The qualification tests presented were conducted in compliance with latest standard requirements. The test parameters were chosen by manufacturer based on experience and knowledge in the high pressure high temperature domain acquired through past projects.
Analysis of results was completed with laboratory examination to allow assessment of tested samples condition, ensuring both flexible pipe body and end fittings are reaching expected performance.
This paper will present the tests performed on a 6" inner diameter 17,500 psi and 150°C rated product, manufactured to demonstrate industrial capabilities and allowing as well to perform tests in realistic project conditions. This qualification work is covering both static and dynamic applications, combining high pressure high temperature conditions with ultra-deep water environmental loads.
Many qualification tests are described, including burst tests, pressure cycling tests and bending fatigue test with angle and tension variations representative of conditions encountered in Gulf of Mexico. In addition, results of material small scale and mid-scale test, also performed, highlight ability of the materials to sustain high pressure and high temperature.
Achievements of flexible pipe qualification conducted are presented to the industry, demonstrating the ability of the unbonded technology to reach design pressure of 17,500 psi and design temperature of 150°C for static and dynamic applications.