bluuebunny/crossref_metadata_2025 huggingface dataset:
Storm Warning
Authors: Brown Alan S. , Bomba John G.
Published: October 2008

STORM WARNING, A Panel In 2005, Hurricanes Katrina and Rita acted like brooms to sweep away 115 production platforms, damage more than 50 others, and capsize, damage, or carry away numerous drilling rigs. While most of the platforms were old, perhaps as many as 20 percent of the platforms and most of the rigs were new and built to the most modern specifications. In addition, the hurricanes devastated the underwater pipeline system that ties platforms to shore. Ten months after the 2005 hurricane season began, 12 percent of Gulf oil production and 9 percent of its gas production remained out of commission.

By April 2006, industry and government organizations had rushed new benchmarks for offshore construction through standards-setting organizations. Although the 2006 hurricane season did not challenge these new standards, severe hurricanes are a certainty in the future.

Our panel includes key members of standard-setting committees, who will provide a high-level review of Gulf Coast readiness to weather another severe hurricane season. They will assess data from the latest hurricane season, project the effectiveness of the new rules, discuss how the industry has used the time bought by the weak '06 hurricane season, and talk about the next wave of proposals.

Introduction

In June 2006, Mechanical Engineering magazine ran an article titled "Storm Warning". This article consisted of a series of interviews with recognized industry engineers and Governmental Agencies to assess the impacts of Huricanes Katrina and Rita on the offshore industry and what the industry did to improve design codes and methods. Why? In the summer of 2005, Hurricanes Katrina and Rita swept away 115 production platforms, damaged more than 50 others, and capsized, damaged, or carried away numerous drilling rigs. While most of the affected platforms were old, perhaps as many as 20 percent of the platforms and most of the rigs were new and built to the most modern specifications. In addition, the hurricanes devastated the underwater pipeline system that ties platforms to shore. Seven months after Rita, 23 percent of Gulf oil production and 14 percent of its gas production remained out of commission.

Industry and Government trade and standards-setting bodies responded faster than ever before. By April 2006, they had promulgated new standards. Although the 2006 hurricane season did not challenge these new standards, severe hurricanes are a certainty in the future.

The Panel's Purpose

By the time OTC '07 convenes in April, it will be time to assess the minimal data from the latest hurricane season, discuss the potential effectiveness of the new rules, and look at how our experience evaluating the past hurricane seasons is shaping the next wave of proposals for changes to the applicable rules and standards.

Our panel includes several of the original interviewees, key members of standard-setting committees and Government agencies, who will provide a high-level review of Gulf Coast readiness to weather another severe hurricane season.
Fatigue Comparison Of Two High Strength Heat Treated Structural Steels For Low Temperature Service
Authors: Graff W.J. , Pinyopusarerk Chao J.
Published: October 2008

Quenched and tempered carbon steels are used in the construction of offshore platforms, refrigerated gas cargo tanks, storage tanks, pipelines, pressure vessels, container ships, ice breaker ships, and other structures which require a high degree of notch toughness at low temperatures or where the increased strength with minimized weight is the dominant factor in design. This paper summarizes the results of 40 plate specimen fatigue tests on two quenched and tempered carbon steels:U. S. Coast Guard specification CG-A-537M, andASTM specification A-537B.

Bending stress and axial stress test results are reported for stress ratios of 0, ½ and -1, representing zero-totension, half-tension-to-tension, and fully reversed loading, respectively. Conventional S-N curves are presented for both steels The A-537B bending S-N curve at a stress ratio of zero corresponds with that for axial loading taken from the literature. For lives up to about 3 × 105 cycles at any positive stress ratio the fatigue strength of non-welded CG-A-53'7M exceeds the yield strength. The fatigue strength of CG-A-537M' is higher than that of A-537B when comparing ratios of fatigue strength to tensile strength. At a stress ratio of the fatigue strength of CG-A-537M exceeds the yield strength for lives of two million cycles. Data for both steels with the tensile strengths are plotted as modified Goodman Diagrams.

INTRODUCTION

In recent years hurricanes have caused great damage to offshore operations in the Gulf of Mexico. In other parts of the world platforms have been extended into deep water and into severe cold regions, such as Alaska and the North Sea. It has become necessary to study the problems of brittle fracture at low temperatures (1). The failures of offshore drilling platforms under severe weather conditions emphasize the need for increased reliability in these structures to protect the large capital investments and human lives.

To solve the problems of brittle fracture at low temperature and to meet the need for stronger offshore platforms with minimum structural weight, designers are now choosing heat-treated carbon steels. These steels not only provide high static strength, good weldability and excellent notch toughness at low temperatures (2), but also have high fatigue strength as reported in this paper.

The purpose of this paper is to summarize the results of fatigue tests on two kinds of quenched and tempered structural steel:a relatively new grade tailored for artic ice breaker and tanker service which is currently designated U. S. Coast Guard specification CG-A-537M, andan older grade ASTM specification A-537B which has been used successfully for the past ten years in offshore platforms as well as in storage tanks for low temperature refrigerated gases.
Toward Low Costs for High Cost Resources
Authors: Bairrington P.D. , Bodwell Bradley , Farnsworth James , Parker Timothy , Pierce Charles , Ross Chris
Published: October 2008

Oil and gas companies are being driven to find and develop resources that are intrinsically higher cost than those that were accessible a decade ago. They must face the challenge of lowering full cycle costs so that they can provide their shareholders with the returns that they have become accustomed to in an environment of volatile and unpredictable commodity prices. In this paper, we draw on the experience of practitioners in US and international deep water exploration and development and unconventional resource plays as well as consultants active in developing strategies and performance improvement programs for high cost resources, to uncover common themes in moving toward low costs for high cost resources.

In the view of the authors, three key themes emerge in the effort to lower costs: scale, excellence in execution and controlled experimentation. Scale is a prerequisite for lowering unit costs and leveraging lessons learned; excellence in execution extracts the full value embodied in scarce skilled employees; controlled experimentation is by definition necessary to continuously rewrite the rules of the game in producing high cost resources and progressively drive costs down. This system, once created, can be deployed in new fields and basins to build profitable growth from high cost resources (See Figure).
Flow Assurance in 30" BUT Subsea Pipeline Without the Usage of PPD
Authors: Prasad Jitendra , Philip P. Cherian , Sharma Vinod , Verma Prem Kumar
Published: October 2008

203 km long, 30?? dia sub sea pipeline transports Mumbai High crude oil to Uran onshore terminus (BUT oil line). In order to ensure that there is no congealing of crude and restartability is easy after prolonged shutdown, Pour Point Depressant (PPD) was being dosed. The average cost of treatment for flow assurance was very high (to the tune of 10 million USD per annum). Expanding database, infrastructure development has led to the present studies to explore the possibility of flow assurance without PPD usage. Extensive rheological studies have been carried out at BHS platform on live Mumbai High crude to analyze the effect of temperature, pressure, shear history, water cut, ageing etc. Results of field and laboratory studies were integrated with the observations made during rupture/ repair of BUT oil line in since1992. Case studies of BUT pipeline rupture in recent past have given authentic information about heat losses and gel strength of the aged crude. Concept of estimation of pour point of live crude (with pressure and lighter cuts) was used for the first time on PPD treated and untreated crude to understand the crude behavior under pipeline conditions. Field experiments in 18 km long BHN-SA sub sea well fluid line were also carried out to understand heat losses and restartability behavior. Bathymetry data from IPSHEM, Goa and software modeling has also been used.

It was observed that cooling of crude oil in the sub sea pipeline is less pronounced than estimated earlier. Restartability of crude oil after prolong shutdown (˜30 days) would not pose any problems. Rheological behavior of crude under pipeline conditions is much better than observed in laboratory. Flow assurance with out PPD usage can be attained. PPD usage has been completely stopped and pipeline is functioning smoothly without any increase of pressure drop / wax deposition.

INTRODUCTION:

Mumbai High- Uran sub sea trunk crude oil pipeline (BUT oil line) is 30?? dia, 203 km long pipeline carrying Mumbai High crude oil to Uran onshore terminus. The pipeline is buried and insulated. The pipeline was commissioned in 1979 and adequate data and information is now available to have relook into the salient aspects of its operation.
A CFD-Based Model to Locate Flow-Restriction Induced Hydrate Deposition in Pipelines
Authors: Jassim Esam I. , Abdi Majid Abedinzadegan , Muzychka Yuri
Published: October 2008

Hydrate is a major risk in all high pressure natural gas transport lines including the connecting lines and manifold systems in all offshore production facilities. Marine transportation of compressed natural gas is one example where prediction of hydrate formation in loading and unloading lines and manifold systems is a requirement for the safe transport of gas to and from ocean going ships. Production facility components such as chokes, velocity-controlled subsurface safety valves, and conventional valves and fittings can all act as restrictions to the flowing fluids, resulting in changes in flow conditions, which could lead to the formation of hydrate in the pipeline.

The principal objectives of our research can be summarized as:to identify the location where hydrate blockage would most likely develop,to study the effect of parameters such as orifice geometry, gas composition, real gas behaviour, and surrounding conditions on the agglomeration spot, andto validate the numerical results with available experimental data.

Numerical simulation using computational fluid dynamics (CFD) techniques is underway to model the mechanism of the deposition based on the most recent theories of the deposition phenomenon. The model uses CFD algorithm for assisting to configure the flow field using real gas models and predicting the actual fluid properties. The nucleation theory and driving force models and their relationships to hydrate formation are also used to predict the incipient hydrate particle size and growth rate.

In this paper, the theory of the deposition mechanism is briefly discussed. The application of the theory in turbulent regime for different hydrate particle sizes is then presented. Finally the approach used for deposition process is discussed.

The study concludes that two phenomenon control the deposition mechanism, namely: the Brownian diffusion mechanism by which the movement of small particles (<1µm) can be explained and the inertia mechanism which controls the dynamics of the relatively large particles. The collection efficiency, the indicator of the deposited particles, decreases as the size of the particles increases in the diffusion region whereas in the impaction region, the collection efficiency increases with particle size.

Introduction

Particle deposition is a process that plays a key role in many fields ranging from atmospheric applications to material sciences. In the oil and gas field, the accumulation of hydrate is one of the most challenging aspects in flow assurance studies. It could partially plug and eventually completely block the natural gas pipeline, causing serious risk to the safety of operating personnel and equipment as well.
ACG Offshore Platforms Temporary Pin-Pile Foundations
Authors: Kitney Neil , Penman Allan David
Published: October 2008

Seabed uncertainties, limitations of marine construction vessels in the Caspian Sea and the size of the two Phase-3 platforms for the ACG development offshore Azerbaijan, led to temporary foundations being needed to support the jackets on the seabed prior to installing the main foundation piles. Pin-piles were selected, requiring development of a sophisticated and innovative scheme for their extremely accurate seabed positioning. A modular space-frame system was designed to position eight individual pin-piles in a single and continuous subsea operation. The system had to be capable of numerous subsea relocations and accurate attitude adjustment to counter a sloping seabed, potential subsidence and have sufficient structural integrity against damage from pile driving loads. Exceptionally tight pin-pile installation tolerances were essential to ensure tieback of pre-drilled wells, bridge linking of the two platforms and accommodation of the piles within the geometry of the jacket legs.

This paper describes the development of the engineering solution from analysis, laboratory testing, fabrication and field trials through to offshore installation.

Introduction

The ACG field is located in the Azerbaijan sector of the Caspian Sea approximately 130 km east of Baku, in water depths varying between 118m and 175m.

Each of the three project phases included the installation of two fixed jacket structures. In order to optimize project delivery a standardized design approach was employed; this included the temporary foundations. For Phase 1 and 2, temporary jacket seabed support was provided by glass fibre reinforced mudmats in each corner of the jacket base, each mudmat having an area in the order of 700m2 (see Figure 1). These foundations were to provide OBS in 10-year return period environments prior to the installation of permanent foundation piles.
Risk Management in the Offshore Energy Industry
Authors: Pollett Buford
Published: October 2008

Based on the earlier work of pioneers in risk management in the offshore industry, the panel will discuss various types of risk associated with the new opportunities and challenges that now face the offshore industry. The various risks include geological and engineering evaluations, commercial concerns, weather risks, and setting contract terms between culturally diverse people. The panel will speak to identifying the risks, setting risk base-lines, and addressing uncertainty. Having a reasonable assessment of risk allows decision-makers to assess the true value and potential return of projects in the offshore industry and provides clear windows of opportunity for investors.

INTRODUCTION

The decision to go forward with new energy opportunities, and pursue an associated offshore project is clearly premised on an expectation of a return on investment. The return, however, is affected by the amount of risk a project bears whether such risk is an operational risk including the use of new technologies or a commercial risk. It is important that each investor have a clear understanding of the known and potential risks. Different parties will be comfortable with different degree of risk. Each party must understand the degree of risk the other party is willing to accept and what type of return is expected. So, it is not only preferable, but imperative, that individuals, teams and entities adopt and use reliable methodologies in order to make informed decisions.

This paper is designed to provide a general outline of the different risks to be considered in an offshore industry project and offers examples of each type of risk. The paper has been written to facilitate discussion and questions for attendees to ask the panel at the conference, and may further serve as an outline or checklist when analyzing and determining various risks in any offshore industry project.

Discussion

I. Operational Risks

A. Geological

Common geological concerns often center on structure, reservoir, hydrocarbon charge and seal.1 Other geological factors can be of a geohazard nature including:Slope instabilityShallow gasNatural gas hydrates and their climate-controlled dissociationShallow water flowsMud diapirism and mud volcanismActive fluid seepage and seafloor pockmark formationSeismicity - which may trigger slides - may cause tsunamis and disturb subsurface geological conditions, e.g. pore pressuresExcess pore pressure development, in relation to fluid migration and sediment accumulationAssessment of geotechnical properties of seabed sediments.2

Geohazards may also be manmade. These manmade geohazards include " existing offshore installations, pipelines or cables, shipwrecks, military dumping grounds, and maritime regulations??.3
Caspian Challenge for Marine Installation
Authors: Wilson Frank , Munro-Kidd Alex
Published: October 2008

The geographical position of the landlocked Caspian Sea presented a huge challenge for the marine installation of the ACG (Azeri, Chirag, Gunashli) development offshore Azerbaijan. Access to the Caspian is limited to two canals in the north which are frozen for up to six months of the year. There was limited reliable hydrographic and meteorological data and the Caspian had a history of relaxed marine discipline.

The ACG Project had a pipe lay barge, heavy lift derrick barge, transportation barge and dive support vessel available for installation activities, all requiring major upgrades prior to utilization. The Project brought in a new supply vessel that was converted into a dedicated subsea construction vessel.

This paper describes the technical challenges, schedule constraints/optimisation and innovative installation solutions from project start through to offshore installation.

The marine installation was successful regardless of the limitations of the vessels and equipment available. Installation included;4 Drilling Templates with 12 well slots (circa 120 te each)Six Jacket Structures (circa 16000te) in water depths from 118m to 175m.Six Floatover Topside Facilities with an installed weight of up to 15800te.4 Brownfield Packages (water coalesor and injection equipment)1200km of Pipelines from 4 to 30 inch diameter.3 Subsea Remote Water Injection Manifolds10 Subsea Remote Water Injection Trees400km of Fibre Optic Cable for telecommunications, IT and integrated control systems.2 Power Cable systems 5.6km and 9.6km in length to provide interfield power.6 Wye Structures (circa 120te each)

Numerous vessel upgrades were necessary to optimise the efficiency of the vessels available to the project. These were strategically planned to minimise impact on achieving key milestones. For the subsea system, facilities to receive, test and store were established.

The contracting strategy with the main contractors proved successful in achieving project delivery targets. Major interfaces were managed with other delivery teams, Company Operations and third party assets.

The ACG Project delivered a number of marine ‘firsts’ in the Caspian, including the floatover of 15800te topsides, wet towing of 600te jacket piles, pre-drilling templates, pin pile temporary jacket foundations and use of underwater hammers. This was achieved through creative design and installation execution strategy, integrated planning across many stakeholders and by significantly enhancing the existing marine fleet with the optimisation of vessel upgrades.
An Overview of the Roncador Field Development, a Case in Petrobras Deep Water Production
Authors: Barbosa Vilmar Carneiro , Dias Ronaldo
Published: October 2008

The giant field of Roncador was by far the largest discovery made in Brazil in the 90's. Holding more than 3.3 billion boe in reserves and located in ultradeep waters - 1,500 to 1,900 meters - its development has set up new technological and economical frontiers for Petrobras's offshore production.

Located in the northeastern portion of the Campos Basin, 125 km off the Brazilian coast (Figure 1), Roncador covers an area of approximately 110 square kilometers and is comprised of two main blocks, saturated with 18 to 31° API oil.

Due to the differences in oil characteristics and to the massive reserves involved, PETROBRAS decided to develop Roncador in modules. This paper describes the track record since the discovery and presents the situation of the field a few months after two new floating units started production: semi-submersible P-52 and FPSO P-54. Petrobras main plans for two other modules in the coming future are also outlined.

Roncador History

Roncador was discovered in 1996, when Petrobras drilled the wildcat well 1-RJS-436A, in 1,853 meters of water, and found an accumulation with light oil (28 to 31o API) in the area which is known today as Module 1A (Figure 2) located in the eastern and deepest part of the field.

Based on the success of its portfolio of offshore projects in Brazil and the good results of PROCAP 2000, its technological capability program to produce oil and gas in ultradeep waters, Petrobras made the decision to develop Roncador with parallel activities, rather than in a more traditional sequential strategy. The company began, simultaneously, to:Drill appraisal wells;Design an Early Production System (EPS) - in order to anticipate revenues and gather reservoir data for the next phases;Design a long-term production system for the northeastern area of the field - flexible enough to accommodate the surprises that would certainly come up along the way;Develop equipment suitable for 2,000 meters of water.

Due to a period of scarcity of deepwater rigs, the appraisal wells were only drilled in 1998. They showed there were different conditions in other areas of the field, which contained crudes with densities varying from 18 to 22o API, and presented a CO2 content of up to 4.5%. Through the years the different areas received several denominations, until a permanent nomenclature was established, as can be seen in Figure 2.
Kuwait Oil Company Employs a Systematic Approach to Ensure Successful Underbalanced Drilling Project: A Case Study
Authors: Kabir Mir Md. Rezaul , Qutob Hani H. , El Saloussy Essam K. , Boutalbi Said Mohamed , Ambastha Anil Kumar , Al Sabea Salem Hamad , Villatoro Jaime J.
Published: October 2008

Kuwait Oil Company (KOC) is considering adapting new technologies to ensure that strategic resources are optimally explored, developed and produced during the life cycle of their oil and gas fields. Among the various options available to achieve these objectives, Under-balanced Drilling (UBD) technology is considered to be one of the most effective methods when it is effectively applied in conjunction with horizontal and/or Multi-lateral well drilling and completion techniques Accordingly, KOC decided to pioneer the introduction of this new technology by employing a systematic scientific approach to screen the Mauddud reservoir in the Greater Burgan field for under-balanced drilling candidacy, in order to ensure a successful implementation of the pilot project.

The screening process incorporated reservoir, production, drilling, Geology & Geophysics and operational data with risk analysis incorporated into a rigorous expert system aimed at maximizing the value of any UBD operation. The screening process was performed in two phases; a high level low resolution screening and in depth high resolution analysis.

Phase I comprised of:Evaluating and ranking the Mauddud reservoir with respect to its risked probability of being successfully exploited with horizontal underbalanced drilling and completion techniques as opposed to conventional methods.Comparing candidate reservoirs against global database of analogues proven to be suitable with UBD.

Phase II comprised of:Quantifying drilling-induced damage and determining the impact on the productivity on the Mauddud reservoir.Comparing under-balanced and overbalanced costs, production rates, projected revenues and Net Present Value (NPV).

This paper describes the expert system methodology used in the screening process and provides a discussion of the results obtained.

The Phase II study findings provided KOC with detailed damage analysis, production forecast and economic benefits that under-balanced drilling could offer as compared to conventional drilling & completion technologies.

The UBD Screening Process

This paper investigates the reservoir suitability of underbalanced drilling using an Expert System screening process that was developed in conjunction with leading industry consultants to increase success in candidate selection and to evaluate the benefits of underbalanced drilling over traditional drilling and completion technology in terms of reservoir performance.

The screening process began by taking basic information for the Mauddud reservoir and processing the information through the expert system phase I software. This software rates the candidacy of the reservoir to help determine the likelihood of achieving success with underbalanced compared to overbalanced drilling and completion techniques. All data input was reviewed for completeness and consistency.
Deepwater Mooring With High Stiffness Polyester and PEN Fiber Ropes
Authors: Davies Peter , LeChat Celine , Bunsell Anthony , Piant Anne , Francois Michel , Grosjean Francois , Baron Patrice , Salomon Karine , Bideaud Charles , Labbe Jean-Pierre , Moysan Anne-Gaelle
Published: October 2008

The benefits of synthetic fiber ropes for deepwater station keeping are now well established and their use is expanding. Nearly all current applications use a single grade of polyester fiber, but for different supports and environments this may not be the optimal choice. Properties of polyester fibers can be modified by adjusting processing parameters and there are other fibers available such as PEN, which offer higher stiffness. This study examines the benefits of intermediate stiffness fibres, stiffer than standard polyester but less stiff than the high performance fibers. The results indicate that there is scope for improving mooring line performance and reducing line weight by careful evaluation of material options.

Introduction

Polyester fiber ropes are finding increasing applications in offshore mooring systems as production moves to deeper water. Following successful installations offshore Brazil in the late 1990's [Pellegrin 1999] the first Gulf of Mexico mooring was for the Mad Dog spar [Bugg 2004] in 2004, which employed 1200 tons of polyester down to 1670 meters water depth. The recently installed Independence Hub platform also used polyester moorings, in 2440 meters water depth [Paganie 2007]. Different rope constructions have been used but these mooring lines were all composed of similar high tenacity polyester fibers. The Red Hawk spar [Haslum 2005], also installed in 2004, used a modified polyester fiber with a higher initial stiffness to facilitate installation, and this raised the question of whether a higher fiber stiffness might be beneficial for other supports and allow rope diameter to be reduced. Previous work within the French Mooring line project [Davies et al 2002] studied high performance fibres such as aramids and HMPE and concluded that their very high stiffness, while allowing much smaller rope diameter and weight, did not improve durability as it would result in high fatigue loading of the metallic components of the mooring line. However, there is an intermediate stiffness region, shown in Figure 1, situated between the currently used fibres, with initial tensile modulus around 10-15 GPa, and the high performance fibers (> 60 GPa) which has not been explored previously for deepwater mooring applications.
Modeling Overburden Stress Change Due to Compaction of Stacked Reservoirs, and Application of Model Results in 4D-seismic and Infill Drilling
Authors: Hindriks Kees O.H. , Schutjens Peter Maarten , van der Horst Juun , Collins Charles Louis
Published: October 2008

A compacting reservoir remains physically connected to the rock surrounding it. Therefore, as the reservoir deforms and compacts, stresses will change and reorient themselves in the reservoir as well as in the overburden, underburden and sideburden, and there will be deformation in these rocks too. It is a well known and extensively described physiological phenomenon that stresses and strains induce changes in seismic velocity. Thus, reservoir deformation induces changes in velocity affecting the seismic wave throughout the basin. For certain combinations of velocity change and overburden thickness, vertical integration of the local traveltime changes may lead to timeshifts of several milliseconds, which can be measured in well-repeated seismic surveys. Timeshift technology has an interesting application in reservoir monitoring: Maps of timeshifts could indicate the areal distribution of reservoir compaction and thus reveal the areal distribution of depletion. Timeshift analysis then has the potential to help determine compartmentalization, locate bypassed oil in undrained compartments, identify new drilling targets and sidetracks, avoid expensive infill wells, and eventually decide when to abandon a field. Promising patterns of timeshifts of up to 15 milliseconds have already been observed in several fields.

We simulated the geomechanical effects of the depletion of stacked oil-saturated reservoir sands. The calculated deformation and stress changes were used to calculate timeshifts as a function of production. Reasonable agreement was obtained between calculated and measured timeshifts. However, the fact that the measured timeshifts resulted from stress perturbation due to the combined effect of several stacked reservoirs complicates their interpretation: It requires a good (i.e. field-data-proven) static and dynamic model for all sands to correctly model their effect on the overall timeshift signal. Only then can the remaining difference between synthetic and field-observed timeshifts be used to monitor and interpret the production performance of a target "problem reservoir" within the stacked pay. Our models also suggest that stress changes in rocks overlying compacting reservoirs are complex and anisotropic, and dependent on proximity and structure of the relatively stiff formations. When these are present, the 3D-variation in stress state, and not the 1D-variation, should be used to compute and analyse timeshifts in 4D-seismic data.
Marine Support to Offshore LNG Terminals
Authors: Gourmelon Jean-Yves
Published: October 2008

Export and import offshore LNG terminals have a bright future… and the technology is here.

As part of the most visible benefits are stranded gas monetization, no land availability issues, reduced administrative pressure, and distance from politically unstable regions.

The Floating LNG industry aims at operating anywhere with maximum uptime, while addressing those familiar and essential concerns: safety, security, environmental responsibility and cost.

Among the challenges presented: access to resources and markets are not always located in the most tranquil waters, and valuable gas reserves can be at a significant distance offshore.

Local regulations might still impose serious constraints. Lastly, LNG carrier maneuvers and cryogenic liquid cargo handling pose different problems while performed in unprotected waters.

Because its role is to assist, protect, supply, maintain, and build, Marine Support is critical to the success of this great adventure.

As it has been with the advances of offshore oil exploration, this industry is coming up with adapted means to serve the emerging Floating LNG activity.

The pioneer of offshore marine support to the oil and gas industry is actively supporting the development of optimized solutions. Its approach is a combination of early project involvement, procedure development, research participation, and innovative ship design.

This paper will develop the notion of " Terminal Integrated Marine Service?? applied to offshore LNG, and describe the " anatomy of a modern LNG Multipurpose Offshore Support Vessel??.

Introduction:

It is assumed in this paper that not everyone is familiar with the emerging offshore LNG industry, its general economic environment, and recent technologies.

The purpose here is to provide an overview on the subject in order to afford an understanding of the marine service context around offshore LNG, and better show the contribution of our industry to its development.

Discussed during years, the move to offshore LNG operations is now clearly underway. It is a " new?? industry with hesitations and complexities, determined to succeed and now evolving rapidly to a more mature stage.

On a marine support standpoint, this " newness?? appears as a mix of " dejà-vu?? and unprecedented challenges. In an offshore stormy environment, how can we safely berth/moor a $200 billion, relatively fragile vessel so it can offload its hazardous cargo?

This view might look extreme…but this is the challenge. Fortunately, we will see that safety requirements, experience, research and technology are here to assist.

Some technology is around the corner that will also bring us closer to the comfortable " dejà-vu?? situation.
AUV and ROV Data Integration to Identify Environmentally Sensitive Areas in Deep Water
Authors: Hewitt Antony T. , Smith Jason , Weiland Richard John
Published: October 2008

This paper describes a methodology for integrating Autonomous Underwater Vehicle (AUV) geophysical data with Remotely Operated Vehicle (ROV) video in order to predict environmentally sensitive deep-water chemosynthetic habitat. The methodology was developed using AUV geophysical data and ROV video acquired in BP's Puma appraisal area, in the U.S. Gulf of Mexico. The results from the AUV survey indicated dozens of hydrocarbon seepage sites with the potential to support high-density chemosynthetic communities. These communities are protected by U.S. environmental regulations and, thus, could significantly impact field development plans. The ROV video revealed a few high-density chemosynthetic communities and cleared certain critical areas for potential development, but it still left numerous possible hydrocarbon seepage sites un-cleared. It would have been a costly undertaking to inspect each site by ROV when they are so numerous and widely separated. Therefore, an alternative means of clearing as many of these sites as possible was needed.

Upon integration of the ROV video with the AUV data, the following important observations were made:Densely populated chemosynthetic communities in the Puma area only occur at hydrocarbon seepage sites with relatively large (several 10's of cm or larger) carbonate outcrops;there is a strong correlation between this carbonate substrate and high-intensity backscatter in AUV multibeam sonar data; and, carbonate outcrops are distinctly visible in the AUV sidescan sonar data as anomalous seafloor mounds.

These observations suggested that ROV observations could be used to calibrate the AUV geophysical data. The calibrated AUV data could then be used to predict what other sites away from the ROV survey track (without direct visual inspection) have the most potential for supporting high-density chemosynthetic communities.

Based on the calibration results, inferred hydrocarbon seepage sites that exceed a specific seafloor backscatter intensity level, and contain anomalous seafloor mounds interpreted as authigenic carbonate, are the areas with the most potential for supporting high-density chemosynthetic communities at Puma. Other inferred hydrocarbon seepage sites that do not meet these criteria have a low potential for supporting high-density chemosynthetic communities, and are less likely to be subject to environmental regulations. The methodology utilized here helped prioritize areas of environmental concern at Puma, incase additonal ROV investigation is required. Additionaly, this method may be applicable in other settings where suitable AUV data and sufficient " ground-truth?? from ROV video exist.
Estimation of Thermal Properties of Methane Hydrate Sediment
Authors: Yamamoto Yoshitaka , Ohtake Michca , Kawamura Taro , Tsuji Tomoya , Tsukada Yuichi
Published: October 2008

Thermal conductivity of real hydrate-layer sand grain, which was recovered from the sediment under sea bottom near Japan, was measured with hot-disc transient method. That of Toyoura standard sand was also measured for comparison. Thermal conductivity of natural methanehydrate-layer sand was 3.8 ~ 5.8 [W/mK] at measured condition (263K~283K, 0.1MPa). This value was lower than that of Toyoura standard sand (8.6 ~ 9.4 [W/mK]) at the same condition. Thermal conductivities of the natural hydrate-layer sand grain and artificial methane hydrate (MH) mixtures were also measured at the condition that imitated the real circumstances of sediment under sea bottom (278K, 10MPa, water saturated). The value was remarkably decreased with the increase of MH concentration at 0vol% ~40vol%. While, it was not so much changed at higher than 40vol%. Estimation of thermal conductivity of natural sand-MH-water three component mixtures was carried out. As a result, the series-parallel conjugation model with varying the contribution parameter reproduced measured values correctly. This is consistent with the idea that structure of measured sand-MH mixed samples should be changed around 40vol% of MH.

INTRODUCTION

Gas hydrate is a clathrate compound that is composed of guest gas molecules and host water cages1. Recently, it becomes well known that there are huge amount of methane hydrate in the sediment under sea floor as same as land areas of permafrost regions. Since this gas hydrate contains large quantity of methane gas, it is considered as one of the substantial future energy resources. Thus, the investigation to recover it from the sea bottom near Japan was launched. In this investigation, thermal properties such as thermal conductivity, heat of dissociation and heat capacity of gas hydrate sediment are very important to evaluate economy of gas hydrate recovery. However, there is not enough experimental data for those thermal properties. Especially, very few data is reported for thermal conductivity of methane hydrate with soil and water2, 3. In this paper, thermal conductivity of natural hydrate-layer sand grain was determined by comparing the measured apparent thermal conductivity of water-saturated samples and that of estimated values with mixing model. Thermal conductivities of the natural sand grain and artificial methane hydrate (MH) mixtures were measured at the condition that imitates the real circumstances of sediment under sea bottom. Estimation of thermal conductivity of natural sand-MH-water three component mixtures was also carried out.
Jet-Induced Trenching Operations: Mechanisms Involved
Authors: Vanden Berghe Jean-Francois , Capart Herve , Su Jason
Published: October 2008

The paper examines the response of sandy sea beds undergoing trenching by steadily moving underwater jets as mounted on jet trenching machines.

While much can be learned from trencher operation data, visualization of the sediment motion is difficult in field conditions.

This motivates the use of small-scale laboratory experiments. The focus is to examine the trenching process and posttrenched sand bed. The processes observed include erosion and entrainment by the jet-induced longitudinal current, infill due to the breaching of the trench walls, and overspill resulting from lateral escape of the turbulent flow out of the trench. These processes are expected to act as well in the field where they may control burial depth and sediment loss from the trench.

The experimental observation were used developed a model based on the gravity- and jet-driven turbidity currents theory.

This model describes the flow of a turbulent layer of water and suspended sand along the sea bottom. It incorporates the following physical processes:entrainment of ambient water and sediment particles into the current;damping of turbulence by stratification associated with the sediment suspension;interaction of the current with sloping topography.

Combined with a breaching model simulating the lateral infill of the trench, this model is able to assess the trench depth and the likely shape of the trench based on the tool travel rate, pump pressure and soil type.

The results of the above work will permit a better understanding of the mechanisms controlling the performances of pipeline burial operations by jet trenching. The proposed model will help the engineers in assessing the performance of the jet trenching machines.

Introduction

During the last years, the offshore industry has used more and more often the jetting power to create trench in the seabed.

The objective of these operations was generally to bury cables or pipelines under a protective layer of sand.

There exists different configuration of these tools. It could be a high power jet moving above the seabed or a ROV (remotely operated vehicles) equipped with jetting swords liquefying the seabed. The ‘product’, cable or pipeline, is first simply laid onto the sea bottom. The vehicle then uses the jetting system to inject high-speed water into the sand bed (see Figure 1). The jets scour a temporary trench, travelling with the vehicle, which allows the cable or pipeline to descend into the sea bed before being buried under the re-depositing sand further downstream of the trencher.
Interaction Model for Steel Compliant Riser on Soft Seabed
Authors: Aubeny Charles Paul , Biscontin Giovanna
Published: October 2008

The use of catenary steel compliant riser (SCR) systems has increased as hydrocarbon production has progressively moved further offshore and into deeper waters. The issue of fatigue damage caused by cyclic interaction of the riser with the seabed has gained prominence with the widespread use and lengthening of the spans. The problem involves a number of complex factors including trench configuration, non-linear soil stiffness, breakaway of the riser from the seafloor, and degradation of soil resistance during cyclic loading. This paper presents a soil-interaction model capable of modelling these complexities, using input parameters that can be obtained with reasonable expenditure. Model simulations for typical offshore soft soil conditions indicate that the model is capable of realistic predictions of cyclic bending moments. Degradation of soil resistance has a major effect on cyclic bending moment, particularly when uplift motions at the riser touchdown point are large.

Introduction

The introduction of these compliant floating systems for offshore hydrocarbon production has led to the development of new designs for the riser pipes, with the catenary steel compliant riser (SCR) often being system of choice. Fatigue stresses associated with extreme storms, vessel movements, and vortex-induced vibrations are critical to SCR performance. The zone at which the SCR contacts the seabed, the touchdown zone (Fig. 1), often proves to be a spot where bending stresses are largest and therefore a critical location for fatigue (Bridge et al., 2003; Bridge et al., 2004). Analyses typically show fatigue damage to be sensitive to seafloor stiffness, which at present cannot be estimated with a great deal of reliability. It should be noted that the vertical scale in Figure 1 is exaggerated for illustrative purposes and typically ratio of trench depth to trench length is small (say 1%) so the problem may be reasonably treated within the framework of a small deflection beam analysis. However, uplift at the touchdown point (TDP) is sufficiently large that the end moment associated with axial tension in the riser should be considered in the analysis.
All Electric Subsea Tree System Development
Authors: Halvorsen Vidar Sten , Koren Eivind
Published: October 2008

This paper will present work that has been completed over the last several years to develop an all electric Subsea control system ending with an all electric tree. The work is now conducted in a joint StatoilHydro-FMC Technologies R&D program; Subsea MMX.

All electric systems provide CAPEX savings from reduced umbilical, OPEX savings from eliminating fluid consumption, and environmental benefits from eliminating emissions of hydraulic fluids.

The basis system discussed in this paper is currently in use for Subsea Choke Control and Manifold Valve Control, and it won the OTC Technology Award in 2006. This system is now further refined for application on safety critical applications like Christmas Tree valves with improved redundancy and fault tolerance in order to meet requirements for safety and availability.

This paper will discuss the analytical development and review of the safety critical electric tree system, as well as describe the technical solutions developed. The development have taken into account the standardisation efforts by the Subsea industry regarding control system interfaces and are compatible with the IWIS and SIIS RP standards.

Introduction

The Electric Tree system was derived from the already field proven All Electric System that so far have been controlling choke and manifold valves on the StatoilHydro operated fields Statfjord and Norne.