bluuebunny/crossref_metadata_2025 huggingface dataset:
The Intellectual Adventures of William Jones (II) : « The Justinian of India »
Authors: Benoit Madhu
Published: June 2014

Sir William Jones resided in India from 1783 to 1794, as a judge of the Bengal Supreme Court. His work on India and the Orient changed the image of India in European eyes forever. However, the Western codes applied by Jones to the realities of India were not always successful. This is clear from his work on comparative mythology and Indian music. In addition, dazzled by the cultural treasures of Ancient India he tended to ignore eighteenth-century India. Even his interpretation and rewriting of Indian law was based on ancient Brahminical law. The result was a mummification of the country, which was to have profound consequences both internally, on India’s legal systems and social structure, and externally, in the way India was perceived by the West – as a country lost in time.
Les hebdomadaires anglophones à Canton, 1827-1837 : quels enjeux ?
Authors: Costantini Iside
Published: June 2014

In the early nineteenth century as British presence was established in China, three weeklies developed in Canton, The Canton Register, The Chinese Courier and The Canton Press. Though they had to survive in a hostile environment, they were used as a medium for missionaries and merchants to interact, whilst China remained closed to foreigners. They gave access to information to a section of the Chinese elite at a time when no comparable Chinese newspapers existed. They were the starting point of journalism in China which enabled the birth of the modern Chinese press.
Résonances de l’Essay on Man dans la poésie anti-jacobine
Authors: Peyroux Roblin Sarah
Published: June 2014

Au milieu des années 1790, au moment où la peur de contagion révolutionnaire atteint des sommets en Grande-Bretagne, certains poètes n’hésitent pas à mettre leur art au service de la propagande politique. Or, pour ces chantres du conservatisme, comment ne pas reprendre le fameux «Whatever is, is right ! » d’Alexander Pope ? Cet article étudie en particulier les ballades contre-révolutionnaires de Hannah More, composées pour les Cheap Repository Tracts (1795-98), qui transforment l’Essay on Man (1733-34) en une démonstration prosaïque des bienfaits du status quo.

Quant aux satiristes de The Anti-Jacobin, or Weekly Examiner (1797-98), cachés derrière le masque d’un pseudo-auteur jacobin, ils raillent les prétentions philosophiques de leurs adversaires en caricaturant leur incapacité à écrire un «anti-Essay » .
Cyclization–endoperoxidation cascade reactions of dienes mediated by a pyrylium photoredox catalyst
Authors: Gesmundo Nathan J , Nicewicz David A
Published: June 2014

Triarylpyrylium salts were employed as single electron photooxidants to catalyze a cyclization–endoperoxidation cascade of dienes. The transformation is presumed to proceed via the intermediacy of diene cation radicals. The nature of the diene component was investigated in this context to determine the structural requirements necessary for successful reactivity. Several unique endoperoxide structures were synthesized in yields up to 79%.
Mineral-Scale Control in Subsea Completion
Authors: Kan Amy T. , Fu Gongmin , Tomson Mason B.
Published: June 2014

Deepwater production is characterized by large production rates from thousands of feet below the ocean floor. Multiple wells are linked to the flowlines on the ocean floor where the produced brines from different wells commingle. Such production system often increases the challenges of scale prevention and control. In this paper, a new thermodynamic Pitzer theory based computer software, ScaleSoftPitzerT?, will be discussed first. ScaleSoftPitzerT? is a MicrosoftT? ExcelTM based program to predict scale tendency, specifically written for the oil and gas production systems. Secondly, the effect of hydrate inhibitors on sulfate scale formation will be evaluated over a wide range of temperature and salinity typically encountered in the oil field. The hydrate inhibitors can reduce the solubility products of sulfate minerals by more than two orders of magnitude. A new speciation model is proposed to correct the hydrate inhibitor effects in terms of a ionnonelectrolyte mean activity coefficient.

Introduction

Formation of mineral scale from produced water in oil and gas wells and pipelines is a persistent problem facing the petroleum industry. Lost production, formation damage, and operational expenses due to scale deposits cost hundreds of millions of dollars a year.

Scale problems are usually associated with specific field condition and operation schemes. Some environmental factors and common practices of offshore production can potentially exacerbate the scale problems. For example, halite scale is mostly observed in the high TDS brine, due to supersaturation condition caused by a reduction in temperature of the fluid during flow through long pipelines and seawater cooling. The primary reasons for the formation of carbonate scales is usually due to supersaturation condition caused by the elevation of pH of the brine as a result of the escape of CO2 and /or H2S gases out of the brine solution at lower pressure. The common cause for sulfate scale is commingling of different sources of brines either due to breakthrough of injected seawater, incompatible brine or mixing of different brines from different zones of the reservoir formation from different wells. A decrease in temperature tends to cause barite to precipitate. In addition, pressure drops tend to cause all scale minerals to precipitate due to the pressure dependence of the solubility product.

In subsea gas wells, hydrate formation is often problematic due to the large temperature drop. Methanol, ethanol, and ethylene glycol are often added in large quantity to control hydrate formation. Such practice has significant adverse effect on scale formation. In the following, the magnitude of scaling problems caused by hydrate inhibitor will be discussed. A new computer program to predict scale tendency and inhibitor need will also be discussed.

Scale Prediction

The thermodynamic-based solubility of mineral salt is defined as the ion activity product at equilibrium.
Prediction of the Movement of an 0iI Spill on the Surface of the Water
Authors: Warner J.L. , Graham J.W. , Dean R.G.
Published: June 2014

A calculation procedure is described to represent the displacement of a surface oil spill under the action of time-varying surface wind stress components; predictions using this technique are carried out for the 1970 Arrow spill in Chedabucto Bay, Nova Scotia.

The procedure presented is based on a convolution integral of the x- and y- components of a time-varying wind stress and is approximated in summation form for computer application. For an impulsive wind stress, it is demonstrated that the summation form is in agreement with an analytical solution by Fredholm.

The Arrow oil spill occurred on 4 February, 1970 and during the first week of March, oil was observed on the beaches of Sable Island some 120 miles Southeast of the spill location. Meteorological data in the form of reduced geostrophic winds have been published by Neu. These winds were utilized to predict the oil spill trajectory based on:a surface velocity equal to 3% of the wind speed and aligned with the wind direction, anda surface velocity determined from the convolution procedure presented in this paper.It was found that the convolution procedure predictions provided better agreement with the available information relating to the spill transport to Sable Island. The importance of an adequate description of prevailing surface currents and vertical eddy viscosity is illustrated.

Introduction

The ability to predict the displacement of an oil slick is essential to proper planning of petroleum terminal facilities and allocation of clean-up resources in the event of an oil spill. The primary factors governing the displacement of an oil slick are the prevailing water currents which may be seasonal in nature and the winds which can be highly variable.

Most of the previous efforts (1),(2) to calculate the displacement of oil slicks have considered the slick velocity to be aligned with the wind velocity with a magnitude of a few percent of that of the wind. It is well-known, however that the earth's rotation causes a surface velocity which, in the northern hemisphere, is directed to the right of the wind vector. Also, the underlying layers of water cause a "memory" effect, Le. if the wind stress vanishes, the water currents exhibit a damped "rotary" motion feature as friction causes the current magnitude to approach zero. The effect of the earth's rotation can be quite significant in predicting the displacement of an oil slick.

The surface velocity (magnitude and orientation) resulting from a given applied wind stress depends on the turbulence structure distribution throughout the depth. The turbulence level is represented (rather artificially) via a linearized vertical eddy viscosity.(Available In Full Paper)

For the general case in which s varies with depth, it is not possible to obtain an analytical solution for the surface velocity due to an applied wind stress. For an s value which is uniform over depth, the solutions for either a steady state wind or an impulsively applied wind stress are presented by V. W. Ekman (3).
Fiber Optic Installation at the Sand Face Enables Real-Time Flow Monitoring and Compaction mitigation in Openhole Applications
Authors: Earles Denise M. , Gill Cooper C. , Stoesz Carl W. , Surveyor Nilufer D. , Pearce Jeremy G. , deJongh Hans A.
Published: June 2014

Subsurface stresses can cause formation faults, slippage, and reservoir compaction, which can damage or permanently shut in a well. Traditional means of detecting these failures are limited and usually require moving a costly rig onto locations, and then interrupting production to re-enter the well. This results in late detection of issues and allows limited counteractive options.

A new system has been developed to actively monitor strain and temperature of wells. The system consists of three key enabling technologies: A fiber optic support device deployed at the sand face, a cost effective high-flow liner system that protects the instrumentation in openhole applications, and two optical wet connects for up to 12 channels.

The fiber optic support device provides a means of holding a helically wrapped optic fiber rigidly in place at the sand face. This new technology can be installed over traditional sand screens in gravel pack or frac pack applications, with no negative impact on the sand control functionality of the screens, or the quality of the pack. The installed fiber optic provides the equivalent of a strain gauge positioned every centimeter along the length of the producing zone.

For openhole applications, a high-flow liner system was developed to protect the fiber optic support device, and the control lines. This system includes a special quick connect that simplifies the on-rig assembly and allows torque transmission in an openhole deployment.

The final key to this system is the two 6-channel optical wet connects, allowing a total of 12 connected channels. This game changing technology provides an information conduit between the fiber optic at the sand face and operators at the surface. The same wet connect can also be used to connect more traditional means of measurements such as pressure temperature gauges, or distributive temperature sensing (DTS).

The information relayed through this system allows the operator to infer flow and detect subsidence or compaction of the sand face before the well is compromised, allowing time to plan and execute mitigative actions. This paper will discuss the design, testing, and potential applications of this new system.

Introduction

The production of hydrocarbons can often cause a decrease in porosity of the rock formation containing them. This phenomenon is known as compaction. Wells can sustain significant damage as the formation layers shift or move along formation boundaries as a result of compaction. Fig. 1 illustrates this type of shift caused by compaction. The wellbore on the left of Fig. 1 illustrates the original location of the well, and the wellbore on the right illustrates the same well post compaction (Earles 2010).
Design and Model Testing of a Shallow Draft Buoy
Authors: Knudsen Borre , Grahl-Nielsen Mette , Ågedal Bjørn , Bruun Per Kristian
Published: June 2014

The FPSO is the most common of the floating platform solutions. The FPSO isgenerally ship shaped (as the Skarv FPSO installed in the Norwegian Sea) butcan alternatively be a buoy with an axisymmetric shape in the waterline (as theSevan Hummingbird operating in the southern North Sea).

For an FPSO with a ship shape operating in mild environment, weather vaning andheading control is not needed and a spread mooring system can be applied, whichoffers a cost effective concept as turret mooring is not required. An area withsevere weather requires the capability to weather vane and heading control ofthe ship shaped FPSO including a turret mooring system must be applied. For anFPSO with axisymmetric shape in the waterline operating in an area with eithermild or severe environment, there is no need for a turret mooring as the shapeof the buoy in the wave direction will be identical at all time.

The difference between the motions of an FPSO and an FSO, with similar storagerequirements, is limited. For an FSO the production topside would be replacedwith a topside shelter. Going from an FPSO to FSO would for the ship shaperesult in a somewhat reduction in length and breadth while for the axisymmetricshape a minor decrease in diameter would be the consequence. Hence, the FPSOand FSO can be considered as a similar concept with respect to motions.

In order to deliver more cost effective FSO and FPSO concepts Aker Solutionshas over several years investigated the possibility of applying an FPSO or FSOwith axisymmetric shape in the waterline. The first concept within AkerSolutions was the Big Buoy FPSO, which later evolved into the Tentech Buoyform. These concepts were based on the possibility of wet oil storage. With the newenvironmental standards set by the Operators and Governments a requirement fordry oil storage has been introduced which will make these concepts lessacceptable.

In order to revisit the potential cost benefit of applying an FSO with ashallow draft axisymmetric buoy shape (avoid turret mooring) having a dry oilstorage, Aker Solutions has designed a shallow draft buoy with a topsideshelter weight of 1500 tonnes and oil storage requirement of normal shuttlingtankers, as for the Skarv FPSO (for comparison of storage requirements). Asizing of the platform based on these assumptions has been done includinganalysis of the platform performance for moderate North Sea environment throughnumerical analysis. A model test has been performed for comparison purpose withthe motion analysis performed.

Introduction

Aker Solutions has extensive experience with FPSO design and has over a periodof 20 years delivered designs for various FPSO's, latest the Skarv FPSO for BP, see Figure 1. The FPSO was installed in 2011 in the Norwegian Sea, west ofSandnessjøen (Norway). All the delivered FPSO designs have been ship shapedincluding a turret mooring system.
Reliable Equipment Shelters for Remote BGV/RGV Stations along the Pipeline - a Key Factor for Arctic Pipelines Operation
Authors: Gropper Jean , Martello Paolo
Published: June 2014

Introduction

One of the most serious problems in strategic pipeline projects is the needfor reliable power for unattended stations in the severe environments underwhich these pipelines must continuously operate (temperatures as low as -55°C(-67°F) in winter, roads to the stations inaccessible for long periods of timemaking the stations inaccessible for maintenance crews, etc).

The objectives for high reliability in BGV/RGV operation, telecommunications, cathodic protection and SCADA/RTU systems in strategicprojects have become staggering. In areas not serviced by commercial power, theproblems faced by the power systems designers are very stringent since thestations equipment must operate continuously on a 24 hour-per-day basis 365days-per-year.

A critical element in the Remote BGV/RGV Stations are the shelters that musthouse all telecommunication, SCADA/RTU, cathodic protection equipment, batteries, UPS, HVAC and fire protection equipment, etc., while maintainingtemperatures enabling correct operation of the installed equipment under thewhole range of ambient conditions, including high winds, strong earthquakes, high snow and rains.

Telecommunications, SCADA, cathodic protection facilities along oil and gaspipelines are mission-critical, carrying vital performance, telemetry andcontrol data without which the pipeline cannot operate.

The use of specially designed, corrosion-proof, weather-proof andwater-proof arctic type, equipment shelters has assisted in solving some of themost stringent problems of the pipeline operators: reliable operation withmaintenance requirements reduced to a visit only once in 6 months or more, andrequired temperature ranges in equipment shelters are maintained, assuringcorrect operation of the sensitive electronics for very long periods of timeexceeding 20 years. Ease and safety of transportation on difficult roads andease of installation in remote areas are paramount factors in the design andconstruction of the shelters.

This paper reviews the key criteria to consider in designing the equipmentshelters and selecting their construction for remote site applications andtheir performance is reviewed. The paper goes on to present case histories inpipeline applications, in Sakhalin and Siberia, which demonstrate their fieldreliability and performance.
Research Activities Planned for the Centre for Arctic Resource Development (CARD)
Authors: Murrin David , Taylor Rocky , Jordaan Ian
Published: June 2014

Hydrocarbon development in arctic regions presents formidable challenges tothe petroleum industry. The Centre for Arctic Resource Development (CARD)serves as focal point for planning, coordinating and conducting research tofill gaps in the knowledge, technology, methodology and training needed toovercome these barriers. CARD research programs have been organized into coreareas of Ice Mechanics, Ice Management and Station-Keeping in Ice, and arerelated through the common activities of Floating System Modelling andLarge-Scale Experiments.

A brief description of proposed research and development (R&D) plans inthe areas of Ice Mechanics, Ice Management, Large-Scale Experiments, FloatingSystem Modelling and Station-keeping in Ice is provided below. Three of theseare core areas, while the activities in Large-Scale Experiments and FloatingSystem Modelling will draw upon expertise from the core areas. Structures andvessels designed for arctic operations must have adequate structural strengthto allow for safe operations under the extreme ice loads expected during theiroperational lifetimes; research in this area is a strong focus of the plannedwork.

The initiatives described in this plan represent the major priorities andrange of activities that CARD will undertake with guidance from the CARDIndustry Advisory Committee (IAC) to overcome challenges associated with arctichydrocarbon development. It is expected that research programmes will befurther developed and refined as Principal Investigators are hired for each ofthe core research areas and they bring the full extent of their knowledge andexpertise into CARD.
The History of Artificial Islands for Oil Exploration and Development in the Alaskan Artic
Authors: Gadd Peter E. , Leidersdorf Craig  B. , Hearon Greg E. , McDougal William G.
Published: June 2014

Eighteen artificial (man-made) islands have been constructed in the AlaskanBeaufort Sea to support oil exploration and production. The first islands, constructed in the late 1970s, were in shallow nearshore waters where wave andice conditions are relatively benign. By the early 1980s, island constructionhad ventured to more exposed sites with water depths approaching 15 m. Innovative slope protection systems and construction methods were developed toaddress the remote Arctic locations, short construction seasons, scarce localresources, and the challenging, yet poorly defined, offshore wave and iceclimate. This paper provides an overview of the history of island developmentin the Alaskan Arctic and discusses design evolution, construction, andperformance.
OPera - Offshore Power System for the New Era
Authors: Fagan Conn , Viteri Martha , Bangstein Bjorn-Harald Kristian , Langeland Tore , Borresen Sven-Erik Kristian , Vage Gjermund Kristian
Published: June 2014

As oil and gas companies extend their presence to remote and ultra-deep waters, one of their main challenges is to maintain environmentally responsible operations while maximizing returns on investment. Attention is directed to the increasing power demand offshore which triggers a quest for alternative and cleaner power supplies.

One proposed solution is presented through the conceptual study abbreviated OPera - the Offshore Power system for the new era. OPera consists of a highly efficient power hub and an electrical transmission system, supplying cleaner power to a network of offshore installations. To detail the OPera conceptual study, the Brazilian pre-salt area was selected as a case example.

The power hub has a gas fired combined cycle power plant that increases power generation efficiency by more than 15 percent, compared with conventional gas turbines alone. The power generation arrangement reduces CO2 emissions with approximately 40 percent. By consolidating power generation, the power hub also allows equipment to run at more optimal load. This is a major benefit, as it further reduces fuel consumption and overall emissions. The power hub is fueled by associated gas or parts of the export gas produced.

The OPera concept is highly flexible in size and configuration, making it relevant for different types of fields. The power plant consists of modular gas and steam units of 50 and 100 megawatt (MW) capacities, allowing the combined capacity to be tailored. Depending on water-depth, different platform and hull-designs can support the power plant. The power hub can connect with different numbers and types of installations, being located in different water depths.
Drill Pipe Riser Intervention System Successful Experience in Offshore West Africa
Authors: De Fonvielle Henri , Bordet Laurent , Marajh Mitra , Campbell W , Susak N
Published: June 2014

While offshore intervention on subsea equipment is quite common, the increasingly deeper water operations require light weight intervention systems while meeting safe and stringent operating specification. For these new deep offshore challenges, the conventional risers are becoming a more costly and less desirable solution.

Starting with a recollection of the main drivers that motivated the development of drill pipe riser intervention systems (DPRIS[i]), the paper details the technical and economical challenges in West Africa that have led to the design of such a solution. When non-productive time and financial aspects are taken into account, it makes sense to develop a dedicated system in order to provide fast and reliable intervention.

Depending on the field requirements, two different types of drill pipe riser systems using a proprietary double shoulder connection were used by operators. A first solution was developed in 1999 featuring a seal ring close to the external shoulder. Subsequently, a new solution featuring a gas-tight metal to metal seal on the pin nose was developed in order to address increasingly demanding and challenging operations.

Intensively used in West Africa since 1999, the solution using the seal ring has shown robustness and reliability while being used for several projects in Angola such as Girassol and Rosa and now GirRI. The paper draws a summary of these operations and the feedback on the field use and maintenance. Also it emphasises the successful qualification process for the metal to metal seal solution that has been used in offshore Nigeria since 2010 for the USAN project.
Use of Fast Response Vessels in Brazilian Oil Spill Response Plans
Authors: Azevedo Bruno Duarte , Possobon Rodrigo , Kammradt Patricia , Matos Michael , Guedes Diogenes , Xavier Gustavo
Published: June 2014

In Brazil, environmental laws define oil containment and collection as a primary strategy to oil spills originated by exploitation and production enterprises that reaches water bodies. Thus, it is foreseen a continuous equipment increase over the time, in a scaled response, always in accordance to accidental scenarios forecasted in the enterprise risk assessment. This way, minor spills, with higher probability to occur, require smaller resources, however made available in a smaller rage of time, whereas larger and less frequent spills must be attended to with strongest resources, in a larger period of time. At Brazilian maritime zones with higher exploitation and production activities the use of larger vessels, aiming to solve the worst cases, was prioritized. Such vessels are also used to respond the small and medium discharges, which could be solved by less robust vessels. The use of smaller and fastest vessels and simpler equipment to be operated allows the fleet's rationalization and a quicker and more effective response to more frequent situations. This changing also fosters economic profits (by reducing the figures and the fees paid by vessels chartering) and environmental benefits (by reducing emissions and the fuel consumption). In order to represent this situation, this paper compares the compliance with requirements from regulatory agency using an exclusive fleet of traditional boats and a fleet of traditional boats and fast response. A case study will be presented, considering a high activity oilfield on Brazilian coast.
Synergies Between Membrane Pretreatment and NGL Recovery in an Offshore Environment
Authors: Tierling Shane , Jindal Sanjeev
Published: June 2014

Interest has been piqued in the use of membranes for the removal of bulk carbon dioxide from natural gas in an off-shore environment because of the advantages that membranes present in weight, space efficiency and tolerance of motion. Integration on the membrane unit into the platform provides opportunities for synergies between hydrocarbon dewpointing membrane pretreatment and natural gas liquids recovery.

Optimization of the hydrocarbon dewpoint pretreatment provides tradeoffs between capital expense, operating expense, weight and natural gas liquids recovery while meeting the membrane hydrocarbon dewpoint requirement. There is an opportunity for the Owner and EPC contractor to define hydrocarbon dewpointing configuration and operating setpoints to maximize the return on investment while meeting the membrane vendor's requirements for dewpointing. Where these opportunities have been identified, direction should be provided by the project to the membrane vendor, whose focus is on the hydrocarbon dewpointing requirements and may not intimately understand all of project objectives including synergies with natural gas liquids recovery.

Introduction

Gas is becoming an increasingly important part of the global energy equation constituting 20.3% of the energy mix in 2010 which is expected to further increase to 24.7% of the mix by 2035 per WEO-2012 (2012) [Fig. 1].
Peregrino FPSO - Operation Challenges Overcome by the Use of Dynamic Simulation from Studies to Training
Authors: Heloin N. Rego , Haarklou Elon , Thiabaud Philippe , Jalby Guillaume , Schiefloe Torgrim
Published: June 2014

Peregrino Floating Production Storage and Offloading (FPSO) is the first heavy oil production facility moored in the Campos Basin 85 km offshore Rio de Janeiro, Brazil. The field is currently one of the largest producing offshore oil fields in Brazil with a daily production capacity of 100,000 bbl of oil, 350,000 bbl of water, and 7.3 MMcf of gas.

The development of Peregrino field, operated by Statoil, provided many development challenges, namely 14°API heavy oil and high water production rates with tight dynamic connection between production streams and produced water circulation requiring specific design and operations. The first phase of the development included two drilling and wellhead platforms linked to the FPSO with two parallel production trains.

Company relied on dynamic simulation and the Life Cycle Simulator (LCS) to master the integrated field layout. The LCS was used throughout the design phase as well as for operator training and verification of Safety and Automation System (SAS).

This paper gives an outline of the Peregrino LCS and highlights the benefits of using this powerful tool for this project. The simulator model is a comprehensive and high fidelity dynamic virtual plant that includes subsea facilities (wells, electrical submersible pumps and flow lines), two wellhead platforms and FPSO topsides process and utility facilities.

In the first phase dynamic studies were performed to validate design options on wellhead platforms and safety systems. Then the dynamic simulator was interfaced with external controller software from the SAS supplier and used to commission the SAS. It was subjected to complete shut-down and start-up tests as well as equipment and instrument malfunctions thus testing SAS in all range of operation and providing a robust operator training tool.

The simulator project has provided an increased understanding of the operational challenges prior to start-up, and helped Company in the development of the Standard Operational Procedures. First production from the field was achieved in April 2011 and is expected to continue until 2040.
Integrated 3D Acid Fracturing Model for Carbonate Reservoir Stimulation
Authors: Wu Xi , Hill Alfred Daniel , Oeth Cassandra , Zhu Ding , Gildin Eduardo
Published: June 2014

Acid fracturing is one of the stimulation methods used in carbonate formations and has been proved effective and economical. Because of the stochastic nature of acidizing in carbonate formation, designing and optimizing acid fracture treatment today still remain challenging. In the past, a simple acid fracture conductivity correlation was usually sufficient to estimate the overall average fracture conductivity in the formation, leading to the computation of the productivity index for fractured well performance. However, the statistical nature of heterogeneity could not be included in the modeling. Understanding the important role of heterogeneity to stimulation performance becomes a crucial step in design and optimization. In order to study the effect of this stochastic nature on acid fracturing, a fully 3D acid reaction model was developed based on the geostatistical parameters of the formation. This made it possible to describe local conductivity distribution related to acid transport and reaction process. In this study, we have developed a new interactive workflow allowing the model of the fracture propagation process, the acid etching process and the well production interactively. This paper presents the novel approach in integrating fracture propagation, acid fracturing, fracture conductivity, and reservoir simulation models in a seamless fashion for acid fracturing design.

In this new approach, the fracture geometry data for a hydraulic fracture is first obtained from commercial models of hydraulic fracture propagation, and then the 3D acid fracture model simulates acid etching and transport on the same gridding system from the fracture propagation model using the width distribution as the initial condition. We then calculate the fracture conductivity distribution along the created fracture considering the geostatistical parameters such as permeability correlation length and standard deviation in permeability of the formation. The final step of the approach is to predict well performance after stimulation with a reservoir flow simulator. The significant improvements of the new approach are capturing the geostatistical effect of the formation and modeling the acid etching and transport more accurately. The paper explains the methodology and illustrates the application of the approach with examples. The results from this study show that the new model can successfully design and optimize acid fracturing treatments.
A Novel Solution to Deepwater Logistical Challenges: Fast Supply Shuttles and High Bollard Pull AHTS
Authors: Kavli Per , Welch Mike
Published: June 2014

Deepwater operations are producing new challenges for operators, as production platforms get larger, and are located fueurability, leading to longer installation times. ther from shore. These platforms are now close to the limit of helicopter range, introducing greater safety concerns and limiting the cargo weights that can be carried, while conventional Offshore Support Vessels travel slowly and would take several days to reach the platforms. Higher power requirements for anchor handling duties means more vessels and more cost, or larger vessels and lower manoeuvrability, leading to longer installation times. In addition proposed maritime legislation will reduce permitted NOx emissions to levels where post-combustion clean-up will be required on diesel engines, adding cost and requiring valuable space.

This paper examines potential solutions to these challenges using a novel design of all-electric ships using LNG as the fuel and the advantages offered over conventional solutions.

The concept Fast Sea Shuttle (FSS) is a high speed multi-purpose 95m vessel capable of operating at transit speeds of up to 40 knots while still carrying considerable cargo loads and enabling rapid personnel transport in relative comfort and safety compared to current methods, and can contribute to the reduction in overall costs of personnel transportation and logistics. The concept 100m AHTS design offers a bollard pull of 380 tonnes while remaining a compact, manoeuvrable vessel. Both vessels are expected to be able to operate in sea states of 4 - 5m thereby reducing waiting time for the weather and providing improved safety for the vessel and its crew.

In addition to novel design features, the key to the high speed of the FSS, and the high bollard pull and fast response time of the AHTS, is the use of an al-electric propulsion system, combining reciprocating engine and gas turbine generator sets for fuel efficiency, using clean-burning LNG as the main fuel. This concept, making use of the high power density and fast loading times f the gas turbines, provides the most efficient solution with reduced weight to maximise speed, towing power, load carrying capability and passenger comfort, while minimizing the environmental impact of logistical operations by using ‘clean’ natural gas.
Improved Recovery Rate in Brownfield Subsea Wells Using Riserless Light Well Intervention
Authors: Karlsen Ole Eddie , Morrison Bevan Jon , Maciel Pedro
Published: June 2014

The combination of increasing global energy demand, known reserves being depleted, and the offshore locations of new oil and gas discoveries is pushing drilling and production into deeper and deeper waters. As a result, the number of subsea wells has increased steadily over the years to more than 5,500 by the end of 2012. Unfortunately, due to their location in deep water, interventions in subsea wells have typically required drilling rigs. Thus operators have been reluctant to perform interventions on these wells. This problem has only been exacerbated as drilling rates increase and sourcing rigs becomes more and more difficult. Thus, recovery factors are much lower—typically 10% to 30% lower—than recovery rates of dry-tree, platform-based wells. Therefore, cost-effective riserless light well interventions (RLWI) are crucial if subsea operators are to realize the full potential of 50% oil recovery (or more) from their subsea fields. This becomes increasingly true as wells age without proper maintenance.

Many opportunities exist to increase recovery rates in brownfields. From milling scale and debris to cutting tubing without using explosives to setting packers and manipulating or changing downhole hardware—all these and much more can be done with RLWI. As proof of concept, several case studies of specific interventions and the resultant productivity increases will be discussed. We will also discuss how adoption and use by North Sea operators has let them increase recovery from 36–46%. For example, Statoil estimated that in 2010, the contribution of RLWI interventions was in the range of 15 billion NOK (2.5B USD).

In addition, we will show the increasing effect pro-active interventions have on recovery rates over time, for selected Norwegian fields. Finally, we will discuss how increased use has made these operations much more routine while also providing opportunities for the technology to evolve. This is a trend that will only continue as operators request additional services in increasingly challenging environments, particularly outside the North Sea.
A Challenging Trunkline ILT Design Driven by S-Lay Installation - A Robust Design Solution Using Advanced Numerical Simulation
Authors: Large Richard , Thompson Barry , Kaliyaperumal Gnanasekaran , Cooper Philip , Zhao Tao
Published: June 2014

Traditionally the S-lay installation loading condition using a stinger is not considered in the structural design of a Pipeline In-line TEE Structure(ILT) during FEED, and is usually only considered during the detailed design. However in a recent FEED project exercise, the S-Lay installation loading condition was found to govern the structural design of the ILT.

Large pipelay forces and moments due to curvature are expected during installation, which required the ILT to be analysed in order to meet the structural integrity requirement during S-Lay installation. Such a design issue requires the attention of the subsea structure designer early in the design process particularly for a large diameter pipeline, in which a high installation loading is expected.

However there are several design challenges in such a design practice. The approach to estimate the pipelay loadings has to give adequate conservatism, considering the range of potential installation vessel configurations. In particular, a high bending moment at the sagbend is expected due to the large size of the pipe, which complicates the design of the ILT structure design and design optimization.

These challenging design issues were extensively explored in a recent project. Advanced numerical modelling was used to assist the design, analysis and optimization. A suite of numerical analysis packages were employed including FS2000, Orcaflex and ABAQUS. The pipe resistance envelope during pipelay was developed using DNV limit state criteria. This pipe resistance envelope was used to derive an upper limit to sag bend bending moments for the local ILT analysis. This paper presents details of the methodology, discussions and conclusions for the engineering challenge described above.
Dry Tree Top Tensioned Riser Systems
Authors: Dunn Greg
Published: June 2014

As oil production moves further offshore and into deeper water, the technology needed to meet the increased demands evolves. New technologies and new applications of existing technologies bring new challenges and often create unintended consequences. For floating production vessels, the riser system is critical to the safety of personnel and protection of the environment. However, there is no universal riser package suitable for every project. The riser system must be designed not only for the environmental loads, but also the specific and unique demands of the vessel.

Project engineers responsible for selecting the best solution for developing a field must maintain a holistic view. The decision of the type of production vessel should be based not only on leading interfaces such as location and environment, but also consider trailing interfaces such as the hardware used on the vessel.

This paper outlines the impact that production vessel type has on top tension riser (TTR) systems. Tension leg platforms (TLPs), spars, and semi-submersibles are considered. Design requirements, functions, interfaces, and standard componetry of TTRs are identified. Case studies of riser packages for various vessel types are presented for illustration. Effects on cost, complexity, installation, and ancillary equipment are documented. Future projections and trends are included.

Introduction

Brazil is a major and growing market for offshore oilfield development. As of August 2012, more floating production projects were planned in Brazil than any other country. With that growth comes an expansion of technology and a diversity of solutions to meet the evolving needs of the marketplace. Upon its planned completion, Papa Terra will be the first dry tree offshore development in Brazil. Given the advantages of dry tree systems in the flexibility for drilling, completion, and workover, many more can be expected in the coming years.

Due to the lack of prior dry tree projects in Brazil, many engineers, project managers, and other decision-makers lack exposure to and experience with these systems. This paper provides general information about floating production systems and their corresponding top tension riser systems. Other components and riser types, such as pipelines and steel catenary risers, are not addressed.
Subsea High Boost Multiphase Pump System Development and Applications
Authors: Cerqueira Maxwell , Kuchpil C. Jose de Castro , Silva Luiz Carlos Tosta , Souza Carlos Eduardo Maia  de , Carbone Leonardo , Huguenin Rafael
Published: June 2014

The paper discusses the development of the Subsea High Boost Multiphase Pump System, which led to the first installation of this technology in the Barracuda field, Campos Basin, offshore Brazil. The Helico-axial High Boost Multiphase pump qualification program was started in 2007 (ref. 6), and went through extensive testing and qualification activities, with the latest endurance test being performed in 2011. The Barracuda subsea multiphase boosting system is installed at a water depth of 1040 m with a tie-back distance of 10.5 km to the P-48 platform and was started up in July 2012. The Barracuda multiphase pump is capable of providing high differential pressure in a wide range of gas volume fractions. The high boost multiphase pump is currently being considered to several other applications worldwide as we move towards deeper waters and longer tie-backs. Some more work is being done so this technology could reach the next step, being qualified to a broader range of applications in order to meet the industry needs. The paper will also discuss current and future applications of this technology, and present the latest status of the Barracuda project.

Introduction

Subsea multiphase boosting is an important technology to the oil and gas industry. Many companies have invested a lot of effort, recourses and time in research and developments over the years seeking to develop reliable and robust solutions for the subsea environment. With more than 18 years since the first field application at the Draugen (Shell) field the helico-axial impellers are currently one of the most important and robust technologies for subsea multiphase pumping.

The initial idea for subsea boosting was to extend satellite production from 10 to 50 km away from existing infrastructure. This would make some field developments feasible as it would allow the same production unit to be used for remote well tie-backs. Another clear benefit of this technology is the possibility to increase the oil recovery and accelerate the production without interfering with the wells or the fluid characteristics.

With the growing subsea activities over the past years the operators faced challenges that required equipment which could be able to add higher differential pressure to the multiphase flow. Without modifying the field proven helicon-axial design the multiphase pump was further developed to be able to handle the required differential pressures.

In 2007 the High Boost pump prototype was designed and built in Norway being first tested in February 2008. After conducting tests over more than 2 years the High Boost technology was qualified. In 2012 the first High Boost pump was started up in the Barracuda field (PETROBRAS - Campos Basin) which has been in continuous operation for more than one year so far.
Development of Worm-Like Micelles as Drag Reducers in Completion Operations
Authors: Martins Andre L , Rodrigues Roberta , Sabadini Edvaldo , Folsta Mauricio G
Published: June 2014

The completion of long horizontal intervals is a challenge faced by Petrobras since the discovery of heavy oil offshore fields in the 80's. The gravel-pack completion is a well know technique applied successfully in hundreds of offshore wells in the Brazilian coast. Besides, the operational limits are frequently very tight, once the water depth has been increased, as well as the desired open hole length. Due to these facts, the pressure gradient is very close to the pore pressure and the gravel-pack setting is the most critical operational step. The gravel transportation by the fluid requires a flow rate that can result in friction losses that can increase too much the bottom hole pressure resulting the formation fracture.

The use of drag reducers is an alternative to perform, the operations in deep water scenario with long wells, as they can lower the bottom hole pressure during the fluid flow. This work aims to present the selection, laboratory and large scale loop tests of nanostructures well known as worm like micelles, used as drag reducers. The main advantage of these structures when compared to conventional drag reducing agents is its capacity of self-assembling. The long nano-structures can resist to pumping displacement, pipe transport as well a contact with solids. It was also evaluated the possible damage of use of wormlike micelles into sand reservoirs, showing they are a real option to perform gravel-pack completion in critical scenarios.

Introduction

Gravel-pack

The gravel-pack operation is a well completion technique generally used in unconsolidated formations. The main objetive is to avoid the production of formation constituints and consequently increase the well completion reliability. It consists in filling the annular space between the formation and a set of screens with sand or ceramic particles that acts as a filter to retain sand from the formation during well production.

The gravel-pack operation performed in a horizontal well can be divided into three distinct stages. The first stage consists in pumping the water/gravel through the work string and gravel tool, where the flow is diverted from inside the column to the annular space. In the second stage (alpha wave), occurs the gravel grains deposition due to decrease in flow velocity, spreading a bed of gravel with relative height (ha) until the end of the well and leaving a free channel between the upper open hole and the top of the bed. After propagation of the alpha wave, starts the third phase (beta wave). In this stage the particles begin to deposit over the bed, filling the upper open channel, as shown in Figure 11.