bluuebunny/crossref_metadata_2025_split huggingface dataset:
Meeting the Challenges of Power Generation on Offshore Heavy Oilfields
Authors: Welch M. , Larsson S. 
Published: October 2015

There are many physical and financial factors that determine the optimum power generation solution on an Offshore installation - space requirements, weight, reliability, and maintenance requirements to name a few. On top of these factors, environmental impacts must be considered, such as emissions of Nitrous Oxides (NOx) and Carbon Dioxide (CO2), and visible pollution like flaring.
Whereas in ‘conventional’ offshore oilfields, there is usually associated gas available to provide the fuel for power generation, Heavy Oilfields provide an additional challenge: they tend to be gas deficient, with insufficient associated gas over field life to fully fuel a power plant. This requires the import of fuel, such as diesel or Heavy Fuel Oil, as these are easily transportable and storable, but importing fuels, and especially premium refined liquid fuels, increases operational costs. Therefore it may be necessary to look at using the produced crude oil itself as the fuel for power generation, and this in itself requires careful consideration by the providers of the different potential power generation technologies.
Liquid fuels also produce more NOx when burned, and are more carbon intensive than most gas fuels, increasing CO2 emissions. Heavy oil facilities usually need more heat for production and processing purposes than lighter crude oils, requiring combustion of more fuel to provide the process heat required and increasing CO2 emissions still further.
This paper looks at the types of liquid fuels, especially crude oil, and alternative power generation technologies that can be considered, and the potential advantages and disadvantages of these technologies in an Offshore application. It also looks at ways of reducing combustion emissions such as NOx and using Cogeneration as a means of reducing CO2 emissions by maximising overall energy efficiency.
A New Method of Producing Mechanically Lined Pipe Including Large Diameters
Authors: Heigl G. , Pavlyk V. , Aretov I. , McCann S. 
Published: October 2015

Abstract
Many offshore oil & gas reservoirs contain unwanted components that complicate the safe transportation of the hydro carbons to onshore refineries. Over time these unfavorable constituents corrode unprotected carbon steel pipelines. In 2013 a pipeline failed in the Caspian Sea within weeks under operational conditions. This high profile failure has already caused many oil companies to rethink their established methodology for pipe lines. Using cladded pipes is a method to safely transport contaminated oil & gas from the well to the cleaning facility. There are various ways to clad pipes with a variety of corrosion resistant alloys (CRA). One category of methods is based on cladding a plate which subsequently is formed to a pipe. The hot roll bonding process is the most dominant route. The second common category of methods is a pipe in pipe solution which is referred to as mechanically cladded pipe. Both groups of methods have their benefits as well as disadvantages but both are industrially proven.
There is a third way to produce clad pipes which can be classified between the two aforementioned categories above. This method starts with a carbon steel plate and CRA strip material so the cladding forms part of the pipe forming process. As this new technique produces a clad pipe product which, from a technical perspective, is situated between the established clad pipe methods, it is called Hybrid Clad®. The resulting bonding strength between the carbon steel and the CRA layer is significantly above that of existing mechanically cladded solutions but lower than metallurgical bonded clad variants.
This paper will provide details of clad pipe manufacture using this new method of production whilst emphasizing the key steps which influence product quality. Secondly, the main benefits and disadvantages of the established clad pipe production methods will be compared with each other and the Hybrid Clad® solution. This comparison is intended to identify the preferred clad pipe product to provide a solution to transportation problems.
Optimizing CO2 - EOR Operations by Improved Conditioning of Reservoir Models to Time-Lapse Seismic Data
Authors: Leeuwenburgh O. , Meekes S. , Hofstee C. , Chitu A. G. 
Published: October 2015

Abstract
Dynamic reservoir simulation models have become an essential tool in oil field management. They can be used to explore the impact of alternative development and operating strategies, and can even be used to search for strategies that are optimal in some desired sense. Robust strategies can be obtained by use of an ensemble of models that are all consistent with available data but that adequately represent the uncertainty. In this paper we demonstrate an application of a workflow to obtain multiple models that are all consistent with historic time-lapse seismic data. We show how these models can subsequently be used to obtain optimal recovery strategies, and discuss how this approach can be extended to optimization under uncertainty.
The history matching step is performed using an ensemble-based methodology and an efficient parameterization of the time-lapse seismic data. The optimization step takes the history matched model (or model ensemble to account for all uncertainty) as input. An approximate gradient computation provides improved strategies. The history matching workflow is demonstrated on a representative sector of a field that is developed with both vertical and horizontal wells and is produced with simultaneous injection of water and CO2.
Evaluation of the history matching step indicates a good match with the seismic data, indicating the power of the parameterization method for handling very large numbers of seismic data. It is discussed that production data can be matched simultaneously, given proper characterization of measurement errors. The optimization step is performed assuming an oil recovery scenario based on alternating water and CO2 injection. Appropriate cost models may be employed to arrive at operating scenarios that result in the maximum expected economic value. Results will depend on, amongst other aspects, the chosen economic model, indicating that best operating practices will be region specific.
The combination of advanced yet practical workflows for assisted history matching and recovery optimization is the result of many developments over the past 10 years. We argue that the cumulative result of these efforts provides significant value to field developments by enabling consistency with measurements, reduction of uncertainties and improved optimization of operational strategies.
Offshore Chemical Enhanced Oil Recovery
Authors: Reksidler R. , Vieira R. A. M. , Orlando A. E. , Costa B. R. S. , Pereira L. S. 
Published: October 2015

AbstractThe design of an offshore chemical EOR project involves not just reservoir engineering, logistics and chemical storage issues. Oil/water separation, produced water treatment, incompatibilities with other chemicals, precipitation on surface facilities and high salinity and hardness water source are among the items that must be evaluated.For polymer flooding, as the main offshore injection water source is seawater or produced water, the salinity and hardness will decrease the viscosifying power of conventional Partially Hydrolyzed Polyacrylamides (PHPA). For small pilots, the chemical consumption of PHPA allows the polymer storage and preparation plant to be whole built on the FPSO deck. Full-field applications may consider independent units for chemical storage and preparation. Proposed full-field alternatives for reducing the polymer consumption are polymers with higher salinity tolerance or reducing the injection water salinity and hardness. Technical and economic analyses are required to compare the alternatives.Another concern on offshore polymer flooding is the large well spacing, requiring polymers with extended thermal resistance in hard water. At elevated temperatures, even modified polyacrylamides cannot resist long enough. It's also recommended to avoid high shear rate regions during the injection, reducing the need of polymer overdosage to compensate the viscosity loss due to mechanical degradation.The ASP/SP method has a considerable higher chemical consumption than polymer flooding. Moreover, regular alkalis cannot be used in hard water, requiring hardness insensitive alkalis or water softening. Water desalinization will be necessary to ensure that the salinity gradient required for the ASP/SP method can be attained. Like for polymer flooding, the application of the ASP/SP method may consider an independent unit for chemical storage and water desalinization/softening. Oil/water separation and produced water treatment must be designed in order to be able to treat the back produced fluids containing the EOR chemicals.Chemical EOR methods are an important strategy to increase the recovery factor of offshore fields, especially where there is no gas available for EOR and thermal methods are not suitable. Important steps are being taken on logistics, chemical and process developments in order to overcome the challenges on making chemical EOR deepwater offshore technically and economically viable.
Benefits of Standardization and Replication in the Bijupira & Salema Redevelopment Project Subsea Tree Design
Authors: Herdocia O. G. , Delescen K. , Rueda L. , Carvalho T. F. 
Published: October 2015

In Q4 of 2011, production from the deepwater Bijupira & Salema fields was on rapid decline. The Operator started to study opportunities for tying in additional wells, but the existing subsea infrastructure composed of three 4-slot manifold was nearly fully utilized with the 12 existing wells. As the study matured over the next 15 months to the Final Investment Decision, the BJSA Redevelopment Project became a full blown brownfield flagship project for the operator, which included 3 new gas-lifted infill wells plus 1 appraisal/producer well into a new reservoir, replacement of the entire subsea control system, suspension of 3 wells, and chemical injection upgrades for the FPSO to support all the changes.
12 months after FID, the opportunity came to fruition achieving first oil on February 2nd, 2014. The execution of the project required innovation in engineering and procurement strategy. Together with its main subsea hardware supplier, the operator came up with a strategy to reconfigure hydraulics, chemicals, controls, and well slots to temporarily suspend production from 3 wells whilst still monitoring them, and gain the facilities to hook-up the 4 new wells. The field had an antiquated control system and used legacy subsea tree systems. Thus, the re-development of the field also required a replacement of the complete subsea control system with the latest technology, and adapting the company's standard Enhanced Vertical Deepwater Tree (EVDT) system used on the BC–10 field amongst other places, to work in the existing infrastructure. The innovation in procurement strategy came in to meet an aggressive schedule with an available rig. The base platform for the subsea trees (XTs) was a global standard tor the operator, enabling the use of available XTs in other parts of the world, resulting in the importation of 3 base systems from the Gulf of Mexico, and 1 from Malaysia to industrialize locally. The design engineering for the XT modifications were done completely locally and involved changing 3 of the XTs to direct hydraulic control and gas lift capable amongst other changes, whilst adapting the Bijupira control system to handle a 4th new SCM based gas lifted XT.
The strategy to manage stock of XTs globally and accelerate a critical schedule for an asset in a particular part of the world is seen as a practice worth replicating and a representative success of the global subsea equipment standardization initiative between the two companies. The value of equipment standardization did not stop at accelerated procurement. By using the same EVDT base design as the BC–10 field that was also in construction of its phase 2, the team was able to easily adapt existing procedures for installation and share tools, spares, a dock side test facility, a tree and tubing head spool installation vessel, and the great talent onshore and offshore that make the biggest impact.
Understanding Complexity and Uncertainty in E&P Mega Projects: The Need for a New Managerial Approach
Authors: Asrilhant B. , Beyda T. T. 
Published: October 2015

Abstract
Mega projects are entities that usually encompass high investment, high participation in the corporate portfolio and high complexity. Complexity is usually underestimated and inevitable in a globalized world based on technological innovation and growing demanding agents, which generally affects projects. Projects grade from simple to complicated and complex. Complex projects consist of multiple, diverse parts that operate in a standardized mode, whose interactions change over time. Because of those mutable interactions associated with possible unwelcome surprises, uncertainty plays a significant role in mega project management.
An important question then arises: how could mega projects could be managed, considering the impacts of complexity and uncertainty. An aggravating circumstance is that a simple project may become complex if immersed in a complex environment. Therefore, the context enhances complexity, notably in mega projects.
This article aims to define mega projects, complexity and uncertainty, and understand the interactions among these three concepts. These concepts and interactions will be applied to E&P mega projects. As a result, the authors propose new knowledge areas that need development and integration with traditional approaches already in use for managing E&P mega projects, which are associated with three dimensions, such as: (1) integration, collaboration and co-accountability; (2) knowledge and technical issues management; and (3) project governance and compliance.
Mass Transfer Parameters in Miscible Flows Across Carbonates Using Computed Tomography
Authors: Vargas J. A. Vidal , Trevisan O. V. 
Published: October 2015

Abstract
The present study presents the development and application of a mathematical model for the 1-D miscible displacement in an intrinsically heterogeneous porous media. The model, referred to as total concentration model (TCM), is developed based on the convection-dispersion equation considering the interaction between the rock and the flowing fluids. The parameters involved in TCM are the dispersion coefficient, the mass transfer coefficient, the effective porosity of the porous medium at the time of the displacement and the amount of solute that is deposited or removed from the porous medium. These parameters are determined in the application of the model through multiparametric matching to the data obtained in the laboratory. In order to evaluate the developed model, two sets of experiments (A and B) were carried out. The tests consisted of displacing two brines across carbonate rock samples. The evolution of salt concentration distribution along the porous medium sample was monitored by X-Ray Computed Tomography (CT).
The great sum of data pertaining to the concentration profiles determined from the CT images in experiment A was analyzed and matched to the TCM model through the simulated annealing metaheuristic method (Simulated Annealing, SA). A dispersion coefficient of 0.01cm2/s for a 1 cm3/min flow rate; and of 0.05 cm2/s for a 5 cm3/min flow rate was determined. The parameters of mass transfer between the fluid and the rock were also evaluated.
Experiment B was carried out in order to double check solute deposition while flowing through the rock sample. Within the TCM model, the phenomenon was quantified by the fr parameter. The concentration profiles were measured at the inlet position, along the rock sample and at the output end. A mass balance calculation was carried out with the obtained data in order to evaluate the fraction of solute deposited (fr) during the experiment. The values determined for fr were 0.2 to 0.4, figures that are consistent with the results obtained with the TCM matching procedure.
The proposed model (TCM) is appropriate for treating data obtained with CT scanners in miscible displacement experiments with relevant interaction between the rock and the fluids. The global matching procedure, considering all curves in the concentration evolution, was used to determine the governing parameters in the model. The amount of data used and the robustness of the method allowed a very good matching of the model to the experimental data.
Using a Unified Controls System for Subsea Production and Pump Controls
Authors: Sommer Burkhard , Völkel Tobias , Dvergsnes Stein 
Published: October 2015

The oil and gas industry tends to seek integrated solutions that provide the full range of topside to subsea equipment and facilities down to the reservoir including installation, monitoring and life-of-field services. The subsea control system plays an important role as the binding element between subsea elements like subsea trees, manifolds, boosting and compression pumps in subsea production systems. The seamless integration of the production control system with the pump control system is the key for the success of providing an integrated solution from topside to subsea.
The most efficient way is to incorporate and merge field proven know-how of pump and production control systems based on existing technologies and accommodate it for future needs. The benefits for the customer are reduced CAPEX and significant technical advantages, being only one interface to the distributed control system (DCS), a minimum quantity of installation and workover tools, less topside and subsea equipment for distribution and control and testing equipment, a fully integrated field monitoring system and field proven components consisting of the best technologies the market is able to provide.
Depending on the project requirement a unified or integrated controls can be realized as an integration of the topside control units by adding the pump control to an existing production control system or vice versa. For new projects a full integration can be achieved from topside to subsea from system to board level.
For full integration, common building blocks from the same subsea control module (SCM) product family are being used. Core components from existing technologies have been thoroughly evaluated and selected to form the basis for the new pump control SCM which completes the SCM family.
With the introduction of the single-unit integrated controls SCM into the SCM family, a wide range of SCMs with a unified interface without losing the knowledge and experience made over years of operation can now be offered. The integration also facilitates the usage of online life-of-field services for pump and production controls in an integrated approach.
This paper addresses the key benefits and the functionality of this technology.
Design Process and Validation of an Autonomous Surface Vehicle for the Offshore Industry
Authors: Coelho R. , Daltry R. , Dobbin V. , Lachaud E. , Miller I. 
Published: October 2015

Abstract
Autonomous systems offer expanding capabilities to provide maritime services in a time where saving costs, creating efficiencies and improved safety are vital. Autonomous vehicles are complex systems and therefore their design and development requires careful and detailed planning. Autonomous Surface Vehicles (ASV) is a rapidly growing company based in the UK with offices in the United States and is a leading manufacturer of Unmanned and Autonomous Marine Systems. Utilising specialist expertise and experience in the design, build and operation of Marine Autonomous Systems, the C-Worker 6 Autonomous Surface Vehicle (ASV) was developed for marine operations support in the Oil & Gas industry.
This paper explores the design and build process from a naval architecture, mechanical, electrical and software engineering point of view, from initial concepts to field operations. The authors also assess the presented method in a meta-design manner. With the initial concept and technology capabilities established, ASV collaborated with Oil and Gas service company Technip to establish industry requirements and define the final configurations accordingly through a dedicated technology qualification process. Technological advancements introduced in this 6 meter long vehicle known as the C-Worker 6, include the integration of multiple offshore payload combinations including USBL, ADCP (current meter), CTD, Multibeam Sonar, Acoustic Telemetry, and Passive Acoustic Sonar (PAM) for marine mammal detection. The robust design incorporating an aluminium, self-righting hull makes the vehicle suitable for harsh ocean environments. C-Worker 6 has a 30 day endurance at an average speed of 4 knots and houses fully redundant power propulsion and communication systems.
As a result of the methodology applied, the product development timeline is presented. The paper also presents data evaluated from real missions. Early qualification of the vehicle has shown its ability to perform in the high sea states of the Gulf of Mexico successfully carrying out subsea positioning in 1300m deep waters with 2.5m waves, as well as having performed Touch Down Point (TDP) monitoring support for S-Lay pipe installation during the technology qualification. The vehicle has since undertaken different mission witch includes a 5 day deployment in the Irish Sea where it held station and extracted data from a subsea platform via an integrated acoustic modem payload, a multibeam survey on a future wind farm installation and Pacific Acoustic Monitoring (PAM) in the Gulf of Mexico.
The interest for using unmanned and autonomous systems to support marine operations in Oil and Gas industry is anticipated to grow with the industry needs and requirements for more efficient, cost effective and safer solutions.
Virtual Core: State-of-the-Art Wireline Technologies To Provide a Viable Substitute for Whole Conventional Coring
Authors: Bize E. , Tisi A. , Laronga R. , Bize-Forest N. 
Published: October 2015

With the increase in activity in deep and ultra-deep water exploration, the need for geological information is penalized by its cost. Acquiring full core data in the current economic context is difficult to justify and encourages the development of less costly alternative methodologies to compensate the lack of information when coring is not included in exploration programs. This is particularly true in oil- or synthetic-base muds (OBM) where such alternative technology is still under development as opposed to the water-base mud (WBM) environment where the technology is more mature and the interpretation workflows are better established.
New state-of-the-art electric wireline technologies including large-volume rotary sidewall coring, and photorealistic OBM-adapted formation imaging combined with powerful software tools for visualization and interpretation are demonstrated to provide a viable substitute for whole conventional core for a wide range of applications, especially in clastic environments.