bluuebunny/crossref_metadata_2025_split huggingface dataset:
Riserless Light Well Intervention: Taking the North Sea Experience to Deeper Water and Higher Efficiency
Authors: Sbordone A. , Morrison B. , Karlsen O. , Sten-Halvorsen V. , Neumann B. , Bjerkvik O. 
Published: October 2015

Abstract
Riserless Light Well Intervention (RLWI) operations have been routinely performed for more than 25 years in the North Sea, with 5 vessels delivering riserless production enhancement operations in several hundred wells, helping the Operators to increase the oil recovery rates from their subsea fields.
The ability to carry out frequent, scheduled interventions as opposed to remedial interventions has proven to be crucial to realize higher recovery rates from subsea wells. Such operations are becoming more common and are moving to deeper water, which brings increased technical challenges. At the same time, the ability to substitute expensive deepwater rigs with smaller Light Well Intervention vessels can have a major impact on project cost and scheduling and represent an even bigger opportunity for cost optimization.
In 2015 a brand new RLWI vessel and intervention package have become available for operations in deep and ultra-deep water, taking the RLWI capabilities and successful experience of the North Sea to the deepwater subsea fields of Gulf of Mexico, Brazil and West Africa. 10 years of experience and track record have been capitalized into the design of a new and enhanced deepwater intervention stack (Stack 4), which is deployed and operated from a state of the art RLWI vessel, the Island Performer.
The new intervention stack, now at its 3rd generation, brings increased efficiency and reliability thanks to smaller umbilical, optimized deployment sequences, easier maintainability, elimination of use of guidelines and simplified control system.
On the vessel side, the Island Performer benefits from larger size, increased lifting capabilities, higher accommodation capacity, higher work floor positioning allowing less green water on deck, sea current monitoring capabilities through the water column, faster tool change-out thanks to additional deployment capabilities.
The paper will give a detailed account of the opportunities to improve recovery rates in subsea wells by enabling access with this lighter, more efficient, and ultimately more productive intervention method. It will also describe and elaborate on the significant enhancements brought to the design and capabilities of the vessel and of the intervention stack, and will illustrate how these improvements make RLWI even more attractive, efficient and cost-effective for Riserless intervention operations in deepwater wells. The paper will also cover the significant testing and qualification activities carried out during preparation for actual operations, including results from wet system integration testing and actual operations performed to date.
Two-Way Fluid-Structure Interaction in a Flexible Pipe Conveying Gas-Liquid Slug Flow
Authors: Vieiro J. , Ita E. I. , Nydal O. J. 
Published: October 2015

Abstract
Some cases of marine operations with pipes conveying multiphase flows can show structural movements depending on the internal flow dynamics. A floating pipe conveying two-phase gas-liquid flow is an example where a two-way coupling between the internal flow and the structural dynamics is needed. The objectives of the paper is to demonstrate a method for dynamic coupling of slug flow and pipe structure simulations by comparing numerical results with small scale experiments on flexible pipes.
Two small scale experimental setups for two-phase slug flow in floating and submerged flexible pipes were prepared. The experiments were designed to give unstable flows. The air and water flow rates were measured and the pipe movements were video recorded. A new coupled model was established, in which a structural dynamic model has been implemented into a dynamic slug tracking model. Forces due to the internal flow such as fluid weight, friction and centrifugal force were included in the structural model, as well as external fluid drag and soil contact forces among others.
The implemented model can reproduce fairly well the dynamic forces due to the internal flow as well as predict the associated pipe deformations and movements. Slug flow can potentially have an impact on pipe dynamics, in particular for cases where severe slugging can occur.
Sanding Onset Prediction on a Ultra-Deepwater Well Using a Probabilistic Approach: From Lab to Field
Authors: Ferreira F. H. , Santos E. S. R. , Rossi D. F. , Borba A. M. 
Published: October 2015

Sand production is a serious problem in many petroleum basins worldwide. It costs the oil and gas industry tens of billions of dollars annually. Additionally, uncontrolled sand production results in costly workover operations and, in some cases, can result in environment hazards due to the release of hydrocarbons associated with catastrophic wellhead and/or production equipment failure. On the other hand, if an unnecessary sand exclusion completion scheme is adopted in one well it will cause oil/gas production impairment and loss of oilfield revenue. Rock strength plays a main role in the analysis of sanding onset prediction. Regarding that subject, the in situ stress and the reservoir depletion are also important players. This article presents a sanding onset probabilistic analysis that takes into account the uncertainties associated to the determination of rock strength and in situ stress over the predicted bottom hole flow pressure at sanding onset.
In order to determine the sanding onset at a sandstone reservoir, the rock strength will be estimated in three distinct scales: small (uniaxial tests), middle (scratch test) and large (wellbore logs and correlations). According to this procedure, it is possible to scale up the rock unconfined compressive strength from lab to field. In parallel, the in situ stress was estimated considering leakoff tests, minifracs and wellbore logs. Finally, an analytical model is used to estimate the stress around the perforated tunnel. As design criterion, it is not permitted that the maximum hoop stress surpasses the formation effective strength (U). This mechanical rock property is related to the cavity strength registered in a hollow cylinder test.
Using this kind of methodology, in a pore pressure vs. bottom hole flow pressure diagram, failure probability contour maps for sandstones were generated for two of Petrobras' ultra-deep water fields. For the first analyzed field, previously to the analysis itself, wells have been completed with fracpack technology. After performing an analytical and experimental study using the proposed methodology, two wells (gas and oil) were completed in a conventional way. Up to this date both wells are producing without sanding. Throughout the article these wells will be called "Well A". The second field is still at the appraisal phase and wells have been drilled in order to estimate rock mechanical properties and in situ stress state with the purpose of minimizing the proposed methodology uncertainty. Based on this analysis, a long term well test will be performed without any sand exclusion equipment inside the well. Henceforth this well will be named "Well B".
The proposed methodology is an assemblage of an analytical simulation of stress around cavities and an experimental effort to estimate the unconfined compressive strength based on lab tests and wellbore logs in conjunction with empirical correlations.
Walk To Work Offshore Using Motion Compensated Gangways
Authors: Salzmann D. Cerda , Prezzi J. , ten Haaf S. , Groenteman S. 
Published: October 2015

This paper describes the operating principle behind motion compensated gangways, how they impact offshore people transfer, the new possibilities and benefits raised by the Walk To Work (W2W) concept. Some examples of vessels designed with this principle are shown.
Ten years ago, W2W with a motion compensated gangway was an unknown concept in the Offshore Industry. People access to offshore structures was basically performed via helicopters or baskets. Nowadays, W2W has become common practice in the North Sea and is spreading all over the world, as a means to increase the number of crew on a platform or to exchange crews in a safe, reliable and efficient way. Active motion compensation technology is the technological driver that enables this innovative concept. The development of accurate sensors, reliable computer power and sophisticated hydraulic and electronics components, motors and actuators, combined with the entrepreneurial spirit of offshore engineers, makes European companies leading in this space.
For the active motion compensation industry as a whole, the ultimate audacious end goal is obvious: eliminate "Waiting on Weather" from the Offshore Industry vocabulary. Although this may be obvious and clear to state, it is definitely a long way ahead of us to actually achieve this vision. However, slowly but steadily, we are getting there. As Walk to Work solutions are advancing in eliminating weather downtime, platforms can be built and commissioned more efficiently, well shutdown durations can be shortened and maintenance or modification work can be planned more accurately. Nowadays, Oil Field Development is required to be all about smarter instead of bigger. The winners of today's oil price fluctuations are the companies that can make use of dramatic decrease in vessel rates and relative cheap shutdown costs, in combination with smart technologies that reduce OPEX costs effectively. The Offshore Industry is a market that is just beginning to open up for the general concept of active motion compensation technology, and at the same time it is essential to embrace this technology in every offshore discipline in order to keep future energy production cost efficient.
Motion compensated crane operations FLNG developments, drilling and well intervention, emergency evacuation are some other offshore activities where active motion compensation is, or will be, a key driver in making the industry smarter and more cost efficient. Offshore motion compensation established itself globally as a reliable part of the offshore ecosystem. But this is only the beginning. The impact on offshore field development budgets can be huge.
System to Telemeasure the Cathodic Protection Potentials Using Fixed Reference Electrodes in Petroleum Platforms
Authors: Bustamante M. A. , Baca A. J. 
Published: October 2015

To capture and display the cathodic protection information in the computer screen of the Onshore Engineers that provide the maintenance of the petroleum platforms, this is achieved using a remote system to send the signal from offshore and installing reference fixed electrodes of silver/silver chloride in the legs of the platforms. The problem is that is very difficult and expensive to obtain the cathodic protection potentials below the surface in the legs of the platforms, because of the difficulty to manage the reference electrode in this site. The operator which is located in the ship is the worker who manage and locate the reference electrode. This task is complicated because of the tilt and depth of the platform legs so that the readings couldn't not be so accurate. The wires and the electrode which are hanging from the top of the ship, are thrown to the subsea along the metallic legs to obtain the cathodic potential readings, the movement from waves and position could affect the accuracy of the readings. To avoid this problem, is proposed and recommended to fix the electrodes to de wall of the legs, far away the anodes installed previously in the structures. This is because the potential signal is weaker in far areas. It is necessary to install many reference electrodes to cover the immerse structures; all depends on the cathodic protection arrangement. Each electrode ought to be connected using wire caliper 14AWG/16AWG to a Junction Box that will be located on the top of the platform. The signal will be sent from the junction box, using systems based on satellite and mobile communications technology or telecommunication systems.
Once the fixed reference electrodes be installed, the cost of maintenance will be substantially reduced, because the rent of ships won´t be necessary. On the other hand the readings will be obtained at the moment, just in the instant time. To improve the system is necessary to install a current rectifier instead zinc active anodes in order to send polarization electrons along the structure. There is no a similar job around the world, so that it could be an opportunity to the Cathodic Protection Engineers to improve their systems, minimizing maintenance costs and obtaining information immediately that is obtained
Proactive and Reactive Strategies for Optimal Operational Design: An Application in Smart Wells
Authors: Abreu A. C. A. , Booth R. , Bertolini A. , Prange M. , Bailey W. J. , Teixeira G. , Emerick A. , Pacheco M. A. 
Published: October 2015

The primary objective of this study is to quantify the benefit of utilizing smart-well technology. The approach presented here maximizes the expected net present value (ENPV) of a field development strategy while accounting for uncertainty in reservoir parameters. In particular the dominant objective is to quantify the relative merits of adopting proactive and/or reactive strategies when designing optimal control policies from their impact on asset value.
Proactive or reactive control strategies are the methods typically deployed for controlling smart wells in the presence of reservoir uncertainty. In the case of an entirely proactive control strategy, the future operational strategy is optimized based on one's current understanding of the reservoir; this approach does not account for new measurements, as and when they become available, and the improved understanding of the reservoir that they bring. In the case of an entirely reactive control, operational strategy follows rules that are tied to future measurements without recourse to a model-based prediction, e.g., the valve may be closed if significant water ingress is observed. In summary, the proactive strategy seeks to prevent an undesired future result, while the reactive strategy actuates the valves when the undesired event occurs. The approach presented in this article combines these two strategies.
This hybrid approach was evaluated against a reservoir model based on the Namorado field, Campos basin, Brazil. The results are compared with scenarios involving a conventional well, but without smart completions, and an entirely proactive control strategy, that does not consider future information. We demonstrate that the approach yields the highest ENPV. The sensitivity of the approach to changes in the number of time steps used for both proactive and reactive control was also considered. For proactive control, the sensitivity analysis examined frequency of valve adjustment in the absence of new information and for reactive control, how fast one needs to react to new and revealing measurement data. This examination revealed that while being operationally proactive is important, there is no value in planning for frequent valve adjustments when there is an absence of new information.
An International Oil Company's (IOC) Development Projects Overview
Authors: Valente C. 
Published: October 2015

Shell's E&P journey in Brazil started back in the seventies when 23 risk services contracts were executed for the exploration in nine onshore and offshore basins. Between the mid-seventies and late nineties, more than 30 wells were drilled on 13 blocks. Almost US$ 400 milion spent on seismic and drilling. This paper presents an overview of field development from the early days to the present.
Between the late seventies and early eighties the discovery of Merluza gas field, in the Santos basin, and other non-commercial discoveries were made. The Merluza development started in the late eighties and was handed over to Petrobras for operation in 1993. The scope considered an offshore platform, subsea infrastructure, wells, gas pipeline to shore and an onshore gas unit.
The Bijupirá & Salema fields, located in the Campos basin, 250 km east of Rio de Janeiro, in water depths between 480 and 880 m, were discovered by Petrobras in 1990 and included in bid round zero. Shell joined the Venture as the operator through the acquisition of Enterprise Oil in 2002 and production started in 2003. It was the first IOC operated development in Brazil with eight producers and six water injection wells. A re-development project resulted in four additional wells with first oil in 2013.
The BC-10 Parque das Conchas deepwater development, also from bid round zero and in Campos basin, is a combination of several distinct small to mid-size fields that allow for phasing. The fields are off the coast of Brazil in about 1800m water depth. This series of successfully phased projects started with the deployment of the Espirito Santo FPSO, 11 wells and subsea boosting equipment in Phase 1 which came on-stream in July 2009. Phase 2 followed on-stream in October 2013 with an additional 11 wells (including 4 water injectors), subsea boosting equipment, and brownfield topsides upgrades on the FPSO. The Phase 3 investment has already added another 7 wells (including 2 water injectors) and will come on-stream in early 2016, after the subsea and topsides scopes are completed.
Practical MPD Deployment Considerations for Floating Drilling
Authors: Bruton J. W. , Lin J. , Patel H. N. 
Published: October 2015

Benefits of using managed pressure drilling (MPD) are already widely acknowledged throughout the offshore drilling industry. This presentation will focus on some of the non-trivial issues that must be addressed in the actual deployment of this emerging technology before implementing it to drill from a floating mobile offshore drilling unit (MODU). This information will be based on the authors' recent and on-going experiences. For deepwater drilling, MPD is not widely practiced and is considered as an extension of industry's new technology. Therefore, sharing lessons learned will help to advance this technology.
A major consideration that must be addressed in the initial phases of any MPD deployment includes integration of MPD equipment with the existing conventional drilling systems. A critical choice to be made as early as possible is whether or not to make the MPD systems a temporary or permanent installation on the particular MODU(s) being considered. There are also class society considerations that must be addressed in offshore MPD deployment discussions.
There is a possibility that MPD equipment manufacturers and their vendors may have never furnished products for offshore utilization on a classed MODU. They may be unaware of the many safety and design related issues involved in receiving and maintaining equipment class certification. The paper will also discuss some of these topics, such as: material traceability, MPD equipment design considerations, offshore maintenance, rig implementation with operator, classification society and repair requirements and the constant safety considerations that must be honored.
The next significant consideration in any MPD deployment is related to the actual ownership of the MPD systems being used. Three possible choices exist: the drilling contractor, MPD service provider(s), or the operating company. Each one of these groups carries several unique benefits and bears additional consequences as well. These issues quickly exhibit circular logic, always leading back to the key question: "Are these to be temporary or permanent installations?" On matters such as: personnel training, equipment maintenance, including the spare parts inventory policies, and MPD operating responsibilities, choices will vary, depending on who owns the equipment, and whether or not it is permanently installed on the particular floating MODU(s).
Finally, the crucial roles of risk exposure and risk reduction in making all of these MPD choices will be examined. Regulatory awareness and their approvals for the intended use of MPD technology can be facilitated by class society involvement early in each project. The matter of who owns the MPD systems will play another role in these risks analyses, and the planned mitigations.
Economic Viability to Trigger the Development of Marginal Fields Offshore in the Gulf of Mexico
Authors: Xochipa O. , Galicia S. , Aramayo A. 
Published: October 2015

This article is based on a new study for marginal fields Crudo Ligero Marino project, whose purpose was to define a methodology and investment options to meet your goals and profitability criteria.
For this case study, five are considered marginal fields assigned to the project, which have been documented year after year without being able to obtain financing to start their stage of development, that having to compete for financial resources to other more profitable fields. To meet this goal aims to generate improvement levers to achieve those investments meet the criteria of efficiency of capital. These levers will be focused on increasing to meet higher investment income and allowing the project to meet its production targets. To accomplish the above, a methodology based on two stages was used. The first to consider the individual assessment of fields, which involve three main aspects: 1) Analysis of current business case, 2) Identification of initially documented and 3) Analysis levers identified value created by levers, for the definition of using levers. The second stage is the search for synergies to review opportunities for production and consolidation of final results, where aspects of production and investment are determined. This methodology was called as MEAPTEC "Methodology for investment projects applying technical, financial and business levers".
The application of the methodology was made by forming an integrated group consisting of a project manager and technical specialists in static and dynamic reservoir characterization, business modelers and financial analysts.
At the conclusion of the study levers of technical improvement and optimization of investments for the development of these fields they are identified. However, one of them was not possible to achieve improvement has mainly concluded that information is not consistent in its exploratory well.