bluuebunny/crossref_metadata_2025 huggingface dataset:
Spectral and Cycle-Counting Fatigue Damage Estimation Methods for Steel Catenary Risers
Authors: Power Thomas L. , Maniar Dilip R. , Garrett David L. , Phifer Ed H. , Vogiatzis John P.
Published: October 2008

Estimating fatigue damage under wind-driven sea loading is of primary importance in the design of steel catenary risers (SCRs) serving floating hosts. For design, the wind-driven sea is modeled as a stationary random process. The resulting dynamic stress in the SCR is also a stationary random process. Spectral methods provide closed-form fatigue damage estimates in terms of statistics for stationary random stress processes. Rainflow cycle counting provides an alternative damage estimation approach that is generally applicable and requires simulation of stress time series. The rainflow approach requires more computation than spectral methods. Damage estimates using the rainflow method may be lower than spectral damage estimates; however, a substantial amount of simulation may be required to quantify the difference.

This paper considers fatigue damage in SCRs attached to both tension-leg platform and semi-submersible hosts. Spectral and cycle-counting estimates are generated and compared. Accuracy of the estimates is discussed, and guidelines for damage estimation are presented. It is demonstrated that the differences between spectral and cycle-counting estimates of lifetime fatigue damage arise primarily from assumptions made regarding the spectral shape of the stress processes of interest.

INTRODUCTION

SCRs accommodate floating host motions through self-flexure. Since host motions persist over the lifetime of the SCR, the task of estimating fatigue damage under wind-driven sea loading is of primary importance in the design of SCRs serving floating hosts. This paper investigates three basic approaches to this task:Spectral damage estimation using results of frequency-domain analysis (Rayleigh and bimodal)Rainflow cycle counting of stress time histories obtained from time-domain analysisRainflow cycle counting of stress time histories created from frequency-domain analysis results

Cycle-counting techniques require the simulation of stress time histories. The accuracy of the resulting fatigue damage estimates depends on the amount (and accuracy) of simulation. Practical computational efficiency considerations have led to the development of spectral methods that match cycle-counting damage estimates for certain forms of stress spectra. Spectral fatigue damage estimation procedures represent powerful and efficient tools for estimating fatigue damage caused by stationary random stress processes because they relate fatigue damage to the statistics of the stress process using a closed-form relationship and do not require creation of stress time histories. The spectral approach will overestimate damage (relative to cycle-counting estimates) when the spectral shape of the process is more broad-banded than the form assumed in developing the spectral procedure.
Two Field Studies Demonstrate That New LDHI Chemistry is Effective at High Water Cuts Without Impacting Oil/Water Quality
Authors: Alapati Rama R. , Lee Jeremy , Beard David
Published: October 2008

The second generation new anti-agglomerate low dosage hydrate inhibitor (AA-LDHI) chemistry is greater than 99% oil soluble and has proven performance to prevent hydrate blockages in both wet-tree and dry-tree applications. This new chemistry has been successful in field applications of water cuts up to 80%. The first generation AA-LDHIs are known to perform at low water cuts, such as less than 40%, and cause poor produced oil/water quality.

Hydrate crystals formed during a flowing condition and/or shut-in condition could form a hydrate blockage and result in a production shut-down. The remediation of such a hydrate plug involves lost revenue, risk for the safety of the personnel and a potential negative impact on the environment. The subcooling involved in deepwater applications is usually higher than 25°F, which would require the use of an AA type LDHI which can protect the production systems up to 50°F subcooling.

Two case studies, one for a wet-tree well and one for a dry-tree well will be presented. The results show a significant decrease in the total oil and grease (TOG) levels in the produced water and percent BS&W in the produced oil. The data will include the performance results, TOG data for long periods of time, toxicity/environmental testing data and shut-in/restart history.

A major benefit of this new chemistry is that the produced water quality is improved compared to the first generation chemistry in field applications. The oil-soluble nature of the new chemistry makes the produced water less toxic and can reduce the chemical costs involved in produced water polishing. The new chemistry can extend the production life of the wells by allowing it to produce at higher water cuts. Given the high crude oil sale price, the new chemistry could add significant value to the producers while not affecting the produced water quality.

Introduction

Hydrate management is a critical aspect of deepwater oil and gas production facilities. Producing wells and flowlines are susceptible to hydrate formation and ensuing blockage if they meet certain criteria. These criteria are the presence of natural gas and water at elevated pressures and low temperatures. The temperature below which hydrates can form increases with increasing pressure and can be as high as 86°F (Kelland 2006). Once formed, the hydrate blockage can take anywhere from a couple of days to months to dissociate, resulting in decreased revenue to the producer due to lost production and other costs associated with the dissociation. The remediation of a hydrate plug poses a significant risk to the safety of the personnel involved and for a potential negative impact on the environment. Dissociating a hydrate plug can cause pipeline/flowline rupture which could injure personnel and release hydrocarbons into the environment.
Four Critical Needs to Change the Hydrate Energy Paradigm From Assessment to Production: The 2007 Report to Congress by The U.S. Federal Methane Hydrate Advisory Committee
Authors: Sloan E. Dendy , Brewer Peter , Charter Richard , Dutta Nader , Johnson Arthur , Jones Emrys , Juenger Kimberly , Kastner Miriam , Mahajan Devinder , Masutani Stephen , Swenson Robert , Whelan Jean , Wilson Scott , Woolsey Robert
Published: October 2008

This work summarizes a two-year study by the U.S. Federal Methane Hydrate Advisory Committee recommending the future needs for federally-supported hydrate research. The Report was submitted to the US Congress on August 14, 2007 and includes four recommendations regarding (a) permafrost hydrate production testing, (b) marine hydrate viability assessment, (c) climate effect of hydrates, and (d) international cooperation.

Introduction

A secure supply of natural gas is a vital goal of the U.S. national energy policy because natural gas is the cleanest and most widely used of all fossil fuels. The relative cleanliness of natural gas, (with the lowest CO2 emission per unit of heat energy of any fossil fuel) in combination with the magnitude of potential reserves, dictates that a comprehensive assessment of domestically available resource be undertaken and included in the national portfolio. Both as a fuel and a feedstock, a secure and reasonably priced supply of natural gas is important to industry, electric power generators, large and small commercial enterprises, and homeowners.

Because each volume of solid gas hydrate contains as much as 164 standard volumes of methane, hydrates can be viewed as a concentrated form of natural gas equivalent to compressed gas but less concentrated than liquefied natural gas (LNG). Natural hydrate accumulations worldwide are estimated to contain 700,000 trillion cubic feet (TCF) of natural gas, of which 200,000 TCF are located within the United States. Compared with the current national annual consumption of 22 TCF, this estimate of in-place gas is enormous. Clearly, if only a fraction of the hydrated methane is recoverable, hydrates could constitute a substantial component of the future energy portfolio of the nation (Figure 1). However, at the present time recovery poses major technical and commercial challenges.

Such numbers have sparked interest in natural gas hydrates as a future potential, long-term source of energy, as well as concerns about any potential impact the release of methane from hydrates might have on the environment. Other countries that import most of their energy, such as India and Japan, are outspending the United States on hydrate science and engineering R&D by an order of magnitude, may bring this resource to market as much as a decade before the United States. It is clear, however, that verifying the role of methane hydrates in global climate change is critical because of the fact that methane has a greenhouse warming potential 21 times that of CO2. A better understanding of the pivotal role that hydrates might play in the global climate could influence U.S. policy choices related to global warming mitigation decisions.
Geomechanics in Integrated Reservoir Modeling
Authors: Settari Antonin , Sen Vikram
Published: October 2008

This paper will discuss the current state of reservoir geomechanics and consider several areas of reservoir development and management where geomechanical influences are important. In order to better integrate our workflows, coupled simulation is often used to exchange parameters between individual modules that are typically run in standalone mode for reservoir flow simulation, seismic modeling or geomechanical modeling. This paper will discuss coupled geomechanics and flow simulation to illustrate several impacts of reservoir depletion (e.g. compaction and subsidence, stress arching in the overburden and casing shear in the wells) and examine the connection between geomechanics and geophysics and areas where coupling of these disciplines can benefit exploration and production. Two generic examples are presented - one representing North Sea chalk reservoirs and the other representing deepwater turbidites.

Reservoir compaction and resulting subsidence are well known examples of geomechanical behavior. During depletion, the reservoir pressures decrease and effective stresses increase. The rocks deform through a combination of elastic (recoverable) and inelastic (permanent) strain, with plastic deformation occurring primarily as the stresses increase beyond the compaction limit or "collapse" stress. The deformation creates a "compaction drive" (additional pressure support) in the reservoir that can improve recovery. However, one must also deal with the undesirable effects - the environmental impact of subsidence, possible fault reactivation, and integrity of wells crossing faults etc. - and geomechanics allows us to evaluate these effects.

In other applications, incorporating geomechanics in the interpretation of repeat 4D seismic surveys improves our ability to isolate and resolve the signatures of variations in fluid saturations. Finally, the primary concern in drilling and completion engineering is wellbore stability during drilling and well integrity during the producing life of the well. The heterogeneity of stress changes in layered reservoirs and overburden due to depletion-induced differential reservoir compaction poses specific technical challenges e.g. casing shear deformation - and geomechanics plays an important role in modeling studies associated with the evaluation of such challenges.
Compact Electrostatic Separation Process
Authors: Taggart Davis Lew , Sams Gary W. , Wallace Harry G. , Manen David
Published: October 2008

Crude oils from mature fields are routinely associated with high water cuts and high operating costs. High water cuts increase the process heat requirements, chemical requirements, overall vessel volumes, equipment footprints and weights. If a significant quantity of water can be removed at lower temperatures, the subsequent production equipment size, weight and cost can be reduced or eliminated. A method to accomplish this ambitious separation goal is being developed by NATCO.

This separation process includes a compact treatment vessel that combines electrostatic coalescence and separation in either a series or parallel process. The vessel design permits both capacity expansions as well as performance improvement by the addition of more coalescing / separating stages. The overall oil-water separation process includes a series of processing steps for:Free gas removalPreliminary free-water separationElectrostatic water coalescenceOil dehydration, andSeparated water treatment.

This paper will concentrate on steps 3 and 4 of this 5-part scheme.

In laboratory equipment using a pipe vessel, NATCO has processed up to 3000 bfpd/ft2 of fluids and achieved an 85 - 95% water removal from oil streams containing as much as 40% water. This compact separation technology has the potential to be applied to either surface or subsea facilities. Using this compact electrostatic separation technology in a subsea environment can provide huge process and economic advantages in deep water applications.

Introduction

Weight and space are at a premium in the offshore environment. The compact electrostatic separator combines several advantages to work well offshore. The separator vessel is " pipe size??; therefore it has a small footprint and weight. In addition the operation is simple with minimal and conventional controls.

Description of Electrostatic Technologies Evaluated

Alternating Current (AC)

Alternating Current (AC) is an older Electrostatic Dehydration technology. The AC process used here applies an alternating electric field at 60 Hz. The voltage can be varied to optimize the emulsion oscillation, which causes the water droplets to deform and accelerates their coalescence. See Figure 1.

Bimodal AC

Bimodal AC is a newer technology that utilizes a higher AC carrier frequency. The potential is modulated between lower and higher voltages at a slower frequency. This additional modulation facilitates additional drop coalescence.
Overcoming Weight Transfer Challenges in Complex, Shallow, Extended Reach Wells on Alaska's North Slope.
Authors: Thomas Randy Lee , McKeever Stephen O. , Hartwig Dennis D. , Egedahl David B. , Patton John , Holtzman Keith , Smith Lee
Published: October 2008

The complex wells currently being constructed to develop the West Sak Field on the North Slope of Alaska (Figure 1) are approaching the limits of extended reach drilling technology (Figure 2). Due to the shallow vertical depth and long horizontal departure of these wells, the ability to effectively transfer weight while drilling and running tubulars can be very challenging. This paper discusses the reasons those challenges exist, and the tools, techniques and learnings employed over the past seven years to successfully solve weight transfer challenges in this remote, environmentally sensitive area, including steerable motor assemblies, rotary steerable drilling assemblies, collaborative planning, on site drilling engineers, torque and drag reduction devices, fluid additives, vibrating down hole tools, and liner running with multiple trips. These learnings enabled the recent drilling and completion of a West Sak well with a total measured depth of 19,750 feet at a vertical depth of 3,055 feet. This well, with a horizontal departure of 18,472 feet and two laterals with lengths in excess of 7,500 feet, has a departure to depth ratio in excess of six.

Background

The West Sak field is within the Kuparuk River Unit on the North Slope of Alaska (Figure 1). The West Sak heavy oil sands contain highly viscous oil due to the low gravity of the crude (10 to 22 degrees API) and the low reservoir temperatures (caused by both the extreme northern latitude and the shallow (3,000 to 4,000 vertical feet) burial depth below 1,800 feet of permafrost in the overburden.) The West Sak reservoir has three primary sandstone targets: the " A2??, the " B?? and the " D?? intervals. The West Sak sands are " very-fine?? to " fine?? grained, single and amalgamated sandstone/siltstone beds. Geologic challenges while drilling include numerous fault crossings along the wellbore (Figure 3) as well as random encounters with calcite-cemented spheroids, also known as concretions (Figure 4). The concretions are much harder than the reservoir sand, having compressive strength of 25,000 pounds per square inch (psi) versus 500 psi for the reservoir sand. These concretions drill much more slowly than the adjacent sand which accelerates wear on the bit, the bottom hole assembly, and the drill string. This difference in hardness can also cause the drill bit to deflect off of the concretions resulting in unwanted severe doglegs. Such doglegs make it difficult to maintain directional control, increase torque and drag, and can cause down hole tool damage.
Geohazard Challenges of the Woodside OceanWay LNG Development, Offshore Southern California
Authors: Hogan Phillip Joseph , Lane Andrew , Hooper James , Broughton Aaron , Romans Brian
Published: October 2008

Geotechnical data, geochronologic data, and high resolution seismic data collected for Woodside's OceanWay Secure Energy LNG project allow an improved understanding of the tectonic and sedimentary processes in Santa Monica Bay and Basin, and identification of geologic hazards.

The proposed facilities are located in a deepwater basin near the collisional transform boundary of the Inner California Continental Borderland (ICB) Province with the Western Transverse Ranges (WTR) Provinces. This area is characterized by complex interactions between blind thrust faults underlying the Los Angeles Basin and strike slip faults related to the northwest motion of the Pacific Plate relative to North America. Active faults and folds crossing the proposed pipeline route present a ground rupture and deformation hazard on the continental slope.

Active sediment transport processes and high sediment accumulation rates are documented on Hueneme submarine fan in Santa Monica Basin (SMB). High-resolution seismic-reflection profiles across Ocean Drilling Program (ODP) borehole 1015 in the basin plain provide a well-dated chronostratigraphic record. Turbidity currents in Santa Monica Basin are sand-dominated, and have increased in sediment volume per event in the latest Holocene. Whilst some turbidites likely result from El Niño-Southern Oscillation (ENSO) storm events, others are believed to have been triggered by seismically-induced strong ground motions.

The potential exists for surface folding and fault rupture, seismically induced strong ground motions, and turbidity currents to affect the proposed pipeline within the lifetime of the project. These geohazards will be mitigated through appropriate analyses, risk studies, and engineering design of the OceanWay facilities, allowing safe and secure importation of natural gas to the West Coast of the USA.

Introduction

Proposed LNG developments in deepwater offshore the West Coast of the United States face new challenges, both on technical issues such as facility engineering and from natural geologic processes. Many recent high-profile deepwater developments continue to encounter major geological hazards (geohazards) on an increasing scale worldwide.

Woodside Natural Gas, Inc. (Woodside) proposes to import LNG to Southern California via a Deepwater Terminal in SMB. SMB is one of several basins in the ICB, a tectonically active area along the plate boundary between the Pacific and North American Plates (Figure 1). A 56-km submarine pipeline will bring the gas ashore via a horizontal directional drill borehole at a landfall in the coastal portion of the Los Angeles Basin (Figure 2). Detailed feasibility and siting studies were performed in 2005 and 2006 to assist in the selection of the optimal location of the OceanWay Project. This paper summarizes geohazards identified during the 2006 geophysical and geotechnical surveys.
Integration of Solid Modeling Into Real-Time Navigation
Authors: Davis Jonathan Peter , Beck Richard D. , Butcher Ron , Nodine Mark  K. , Clarke James P. , Simpson Richard , Benitez Luis , O Leary John E. , Smith Perry
Published: October 2008

The Downed Platforms project deals with seven platforms containing 59 wells which were toppled during Hurricane Katrina in water depths ranging from 86 to 135 feet. Visibility at these depths in these locations is limited at best. As part of an effort to extend the ability of remote operated vehicles (ROV) to work in low visibility, solid models of downed platforms were built and were exported into a form which could be used in the real-time navigation system for offshore vessel, ROV and diving operations. The paper will discuss:Zero Visibility Operations - The Initial ConceptSubsea Model DevelopmentNavigation System DevelopmentIntegrating the Model with Navigation for Field DeploymentROV Control System IntegrationModel Maintenance

The paper will describe techniques which could be applied to subsea navigation in complex environments, where model based positioning can deliver operational efficiencies. Key elements of this system are the structural model and the deployment of navigation system components to ensure accurate and high update rate positioning.

The paper will present results from various stages of field work. While many technologies presented in the paper are pre-existing, the integration of all systems to enable continued operations in zero visibility represents a new application. The application of these technologies increased the operating envelope for the ROV, enhanced co-ordination and safety of activities in the field and in the project and presented significant advances in subsea positioning, control and navigation.

Background

The 2005 hurricane season was the most active on record and hurricanes Katrina and Rita inflicted major damage to Gulf of Mexico (GoM) production facilities on the outer continental shelf (OCS). Seven platforms were completely destroyed in the Grand Isle 41/43/47 field, or " downed??. All platforms located in the Grand Isle (GI) and West Delta (WD) lease areas are in water depths from 86 to 135 feet. The locations were GI 40B, GI 40F, GI 41A, GI 47C, GI 48D, WD 69C, and WD 69K (Figure 1), which are all within 20 to 35 miles west of the centerline track of Hurricane Katrina.
Collaborative Effort Enables Repair of Prolific Gas Well With Solid Expandable Chrome Liner
Authors: York Patrick
Published: October 2008

A prolific gas-condensate well in the Caspian Sea was forced to shut in due to a leak in a premium connection of the 7 in. production tubing resulting in loss of well integrity. Immediate repair was required to re-establish production. An expandable tubing patch (solid expandable cased-hole liner) was selected to provide a high-pressure, gas-tight, and potentially long-term repair of the leak while minimizing the loss of wellbore internal diameter (ID). In a very short time frame, engineering teams successfully collaborated to design, manufacture, and qualify the expandable tubing patch to a V0 (zero-bubble acceptance criterion) test protocol.

The tubing patch was successfully installed without killing the well using a single downhole barrier and a snubbing unit. The well was returned to production in May 2007, and has been on continuous production without any evidence of a re-occurrence of the tubing leak. This paper will review the well engineering, design engineering, qualification testing, QA/QC, and operational installation planning. Close teamwork between the end user and the expandable provider resulted in the successful repair of the well and allowed the operator to progress the return of the well to service.

Introduction

The Shah Deniz field, confirmed in 1999, is a giant high-pressure gas condensate field containing approximately 30 TCF of gas and a significant amount of condensate offshore Azerbaijan in the Caspian Sea (Figure 1). Shah Deniz Stage 1 sanctioned 12 wells with further development planned in the field with a life estimated to more than 30 years. Well conditions are near HPHT with a reservoir pressure of 12,500 psi at 20,000 ft (~6,100m) TVD and a static reservoir temperature of 212°F. Drilling and production occur from the Shah Deniz Alpha (SDA) platform in water depth ~330 ft (~100m) (Figure 2). Licensees and subsequent interests in the Shah Deniz Exploration, Development, and Production Sharing Agreement (EDPSA) include the following:BP, operator - 25.5%StatoilHydro - 25.5%State Oil Company of the Azerbaijan Republic (SOCAR) - 10%LUKoil - 10%Nico - 10%Total - 10%TPAO - 9%

Wells producing from the Shah Deniz field are among the most prolific in BP's global portfolio. As such, the integrity of these wells is essential to the company's strategy for exporting gas from the Caspian Sea.
The Greater Plutonio FPSO: Mixed Contracting Strategies to Optimize Delivery
Authors: Stewart Graeme
Published: October 2008

Large scale integrated projects are becoming increasingly common across the industry, requiring a complex series of multiple activities to be co-ordinated to reach a successful conclusion. Development of the Greater Plutonio project in Angola Block 18 required the construction of a world scale FPSO, similar to those used in other developments offshore Angola. Typically, similar projects have adopted an EPCI contracting strategy, where the FPSO is designed, constructed, installed, and commissioned under a single lump sum contract.

During the early stages of the Greater Plutonio project development, it became apparent that there were some potential disadvantages in this approach. In a number of cases, the design contractor who had been involved in the front end engineering design was not part of the successful bidding consortium, leading to a change of designer and associated rework. Additionally, there are a very limited number of companies capable of bidding and winning large scale, fully integrated FPSO contracts. At the time of bidding for the Greater Plutonio, a number of these companies were fully occupied in other oil industry work, which would have led to an uncompetitive bidding situation.

This paper describes how a different approach was used for the Greater Plutonio FPSO, unbundling the contracts into smaller packages which were tendered and awarded separately, which delivered a successful outcome.
Emerging Geophysical Technologies: Is Planting and Re-Planting of Nodes in a 4C-4D Scenario the Optimum and Most Cost-Effective Solution for Field Reservoir Monitoring?
Authors: Berg Eivind , Vuillermoz Claude , Woje Geir , Ekmann Gunnar
Published: October 2008

Seabed data acquisition methods offer numerous advantages over towed streamer data. These advantages can lead to improved static and dynamic reservoir characterization. By recording complete vector field data at the sea floor with full azimuth acquisition improved shallow resolution, signal-to-noise ratio, spectral content, deep imaging and 3D illumination can be achieved. Also in the presence of obstacles such as production facilities a regular coverage can be assured.

Autonomous node technology has been developed to a fully commercial system. It has demonstrated improved imaging of complex reservoir with both pressure (PP) and converted shear (PS) with stable and consistent measurements achieved by very well planted nodes into the sea floor and full azimuth acquisition with densely sampled shots.

It has been experienced that the background response from well planted nodes can be repeated in a 4C-4D scenario when the coupling conditions are the same. The vector fidelity in the node system will secure this behavior. In addition, the accurate positioning and re-positioning of the nodes under realistic water depth ranges gives positioning accuracy close to permanently buried cable systems. An experiment performed on the Volve field in the North Sea with pairs of nodes planted side by side clearly confirmed the high degree of stability in the coupling and the repeatability of the measurements from all components. At 100 m water depth all the planted nodes were within a short radius around the pre-plot position.

A cost sensitivity study of different 4C-4D node scenarios depending of field size, water depths and node spacing indicates that, for larger field sizes (300-600km2 receiver coverage), the alternative use of nodes could be significantly more cost effective than permanently buried cable systems. Moreover, there are advantages linked to the acquisition geometry, operation, zero equipment life time risk and low initial investment.

Introduction

Marine seismic exploration and reservoir imaging have been through numerous stages of adjustments and improvements. Towed streamer surveys from 2D to 3D and now to 4D dominate the offshore seismic survey with a well established technology which remains the most common acquisition with narrow azimuth coverage. New techniques such as " single sensor recording?? (Egan et al, 2005), " over-under?? (Singh et al, 1996) and " wide azimuth?? (Campbell et al, 2002) have recently delivered impressive results. These techniques have raised the cost and complexity to more traditionally " simple?? towed streamer operations.
Collaboration for EPC of Offshore Structures
Authors: Shin Hyun-Soo , Sim Woo-Seung , Moon Joong Soo , Yoon K.Y.
Published: October 2008

Korean shipyards have been leading the construction of newbuilt offshore structures in the last 10 years. HHI (Hyundai Heavy Industries Co.) is one of major EPC contractors and has successfully built several FPSOs, drilling rigs and FPUs intended for worldwide operation. HHI has established a strong reputation in construction as the world leading shipbuilding yard and has highly experienced workforce. Numerous novel methods enhancing HHI's competitiveness were employed in its recent endeavors. They include new construction methods (Ground Build Method), work on new technologies in collaboration with external research entities and participation in JIPs; the recent one focused on nonlinear impact fluid forces due to slamming, green water and viscous roll damping.

HHI is also well established in the area of hull design for offshore industry. It has recently designed fatigue free FPSO using FMS (Fatigue Methodology Specification) co-developed by EMDC and DNV.

HHI can respond with high degree of flexibility to client's needs as it owns extensive facilities (several dry docks) and has mastered effective project management methods. This paper summarizes the recent successful offshore projects from the perspective of accomplishment through collaboration.

Introduction

From the last decade, Korean shipyards have been at a No. 1 position in newbuilt FPSO market. As presented in Table 1, Korean shipyards had 16% and 9% share of FPSO hull and topside fabrication market respectively until 2007[1][2][3].
Navigational Aids in Offshore Operations (With Particular Reference to the European Area)
Authors: Holloway Douglas R.
Published: October 2008

1. Introduction

The history of the North Sea oil and gas fields is now too well known for detailed comment but it is worthy of note that it is still not ten years old and developing at an ever increasing pace. There are already signs that the areas of intensive exploration to be followed by production are extending from the North Sea into areas west of the Shetlands, and through the Irish Sea into the area of the Bristol Channel commonly known as the 'Celtic Sea'. European nations, almost without exception are participating in this frenzy of activity, aided and abetted by their United States colleagues who have such a tremendous wealth of experience.

This concentration of international effort implies a rapid growth of traffic and potential obstructions in this area which means in turn that reliable and effective aids to navigation are absolutely essential on both fixed structures and moving vessels. The purpose of this paper is to describe in some detail the factors influencing the choice and design of such aids to navigation and to illustrate ways in which these problems have been and are being solved.

As the greater proportion of this work is going on in the British Sector, most of the information in this paper is related to that area but the technical aspects are common throughout the whole of the North Sea.

2. Brief History and Background

The North Sea is a continental shelf area of something like 200,000 square miles in extent surrounded almost completely by a number of nations. Interest in the possibility of hydro-carbon deposits in this continental shelf was stimulated by the gas discoveries in Holland in the late 1950's, and this was followed by the Geneva Convention of the early 1960's which was an international agreement concerned with the methods of dividing up national responsibilities for continental shelf areas. The basis of the sub division of the area is the so called Median line which is the locus of a point moving equi-distant from the nearest base line of each state. The allocation of responsibility is shown in Figure 1 by the continuous lines. Britain is fortunate in receiving approximately half of the total acreage but Germany fares very badly. Norway is rather a special case because of the Norwegian trench just offshore which has depths of the order of 2000 feet as compared with the average depth in the North Sea ranging from 300 to 600 feet in the North and 100 feet over the Dogger Bank.

Starting in 1964 the countries concerned began to award licences for exploration and development at an ever increasing rate and at the time of writing this paper there are approximately 75 groups of oil companies and associated concerns engaged in either exploration or production in the North Sea. The number of licences being operated by these groups totals 675.
An Assay of Marine Mineral Resources In Massachusetts Bay
Authors: Lassiter J.B. , Soden James E. , Powers Robert B.
Published: October 2008

A probabilistic model for estimating the volume of sand and gravel resources in an offshore area has been developed. This model has been applied to the analysis of core and grab sample data taken along the western margin of Massachusetts Bay. Through the use of Bayesian and classical statistical techniques, expected volumes of sand and gravel have been calculated for specified subdivisions of the western Massachusetts Bay offshore area. These probabilistic estimates are compared with other available estimates for the region. Problems and prospects in applying this type of modeling to offshore mining are discussed.

Introduction

For some years, proponents of operations research have proposed the use of probabilistic modeling in the exploration for and development of mineral resources. These techniques have met with some limited success in both the petroleum and hard rock mining industries. However, the most widely used method for estimating the volume of extractable resource associated with a specific deposit is what we might call the "educated trapezoidal rule". In other words, the geologist and mining engineer gather the available data, delineate the deposit, estimate the spatial distribution in grading, and then calculate the implied volume of extractable resource as a function of market price. The "educated trapezoidal rule" is the implicit application of the subjective judgment of the people involved coupled with the objective information available. In this paper, we will develop a probabilistic model for determining the volume of economically extractable sand and gravel from an offshore region. We will apply this model to a relatively well-known offshore region and compare the model estimates with those from other available sources. In doing this, we will not attempt a complete economic analysis, but rather will restrict ourselves to the first question which the geologist must answer, namely: how much recoverable sand and gravel of a specified grade is located in a specific area?

In the development of the model, the western margin of Massachusetts Bay was chosen as an offshore region which could serve as the baseline against which model predictions could be measured. A number of individuals such as Emery (1965), Schlee (1968), and Manheim (1972) had pointed out the presence of significant sand and gravel deposits near major northeastern metropolitan areas, among them Boston. Extensive studies by the staffs of the Woods Hole Oceanographic Institution, the U.S. Geological Survey, the U.S. Army Corps of Engineers and the Division of Mineral Resources of the Commonwealth of Massachusetts had resulted in a large amount of physical and subjective data with which to compare our model. In addition, the prospect of a New England Offshore Mining and Environmental Study (NOMES) in the area had incited considerable public debate on 'the topic of sand and gravel deposits in western Massachusetts Bay. with these factors in mind, we chose this area for our comparative baseline.
Ocean Engineering Educational Program
Authors: Herbich John B.
Published: October 2008

The results of two surveys led to recommendations regarding undergraduate and graduate programs in ocean engineering. The first survey consisted of interviews with marine-oriented industry, state and federal governments and NOAA Sea-Grant Program representatives. The second survey was based on a questionnaire sent to educators in leading engineering schools to determine the type and content of ocean engineering courses offered, or planned.

The need for both undergraduate and graduate programs in ocean engineering was evident from the first survey and the extent of courses or programs in this field was determined from the second survey.

Basic engineering as well as applied courses are discussed for the undergraduate program. A "core" program covering ocean environment, material behavior, human factors, communications in the ocean, operation and instrumentation is recommended. The "core" program should be followed by applications in many areas of ocean engineering which should involve such courses as coastal engineering, marine soils and foundations, ocean structures, coastal sediment processes, estuary and harbor hydrodynamics, shallow and deep ocean dredging, ocean instrumentation, corrosion in ocean environment, marine transportation systems, etc.

The nature of the programs as well as their relation to existing disciplines is discussed. Existing programs are reviewed and summarized. Research plays an important part in graduate programs.

INTRODUCTION

A great deal of interest, both public and private, has been shown in recent years in activities related to the usage and development of estuaries, coastal areas, offshore and deep ocean locations.

Only the oceans can meet the increasing demands for protein, power generation, minerals and fresh water. Anyone of these requirements would require a major and accelerated effort and each will require engineering in the ocean or ocean engineering.

Much is being said and written about the subject of Ocean Engineering. In the absence of a definition of the term, continued discussion is adding to the confusion concerning its proper scope.

New educational programs are emerging with the objective of satisfying the need for engineers especially trained to meet the technological problems of the ocean. While flexibility in program development has merit, it would seem important to determine 1f there is same mint with respect to the goals of Ocean nearing education.
A Mud Density Analysis for Floating Drilling Operations In Wildcat Areas
Authors: Bolt Donald  B. , Bercegeay E. Paul
Published: October 2008

A new detailed analysis of floating drilling operations to determine the proper mud densities required for sub sea wildcat wells leads to the development of an equation for calculating fracture gradients in open hole below the first casing string. The effect of penetration rates and the resulting cuttings load on mud density is discussed. The penetration rate is related to fracture gradient in an equation derived for this section of the hole.

Because mud density requirements change instantaneously when the riser is removed to run casing, an equation has been derived to calculate the mud density required to keep the mud column pressure constant in the drilled hole prior to and after riser removal. The procedure presented will prevent a well kick when the riser is removed.

Kicks can seldom be contained without fracturing the formation while drilling the surface pipe hole; therefore, the heaviest mud density possible should be considered to allow high pressured zones to be drilled with maximum safety.

The mathematical analyses regarding kick tolerances and mud density are given using actual drilling conditions which indicates that sometimes a gas kick cannot be taken and contained without fracturing the formation at the last casing shoe. Therefore, depending on the kick tolerance the lowest or highest possible mud densities should be considered in preference to normal densities.

INTRODUCTION

Throughout oilfield history man hasdrilled wildcat wells. The first wells were drilled without regard for the mud densities required to safely seek total depth. Many times this resulted in loss of control of the well.

Drillers hypothesized that wells could be controlled if mud densities exerted pressures that were equal to or greater than formation pressures. This theory was valid; however, in most cases formation pressures were unknown until the formations were penetrated.

Hence, well control loss still occurred but less frequently. Some drillers thought that blowouts could be entirely eliminated if high mud densities were used. Drillers sometimes used such high mud densities that weak formations were fractured causing whole mud to flow into these zones. Drillers found that lost returns could be prevented by placing casing in the hole and cementing the casing-hole annulus thus isolating formations behind the pipe from the hole drilled below the casing.
Hydrospheric Navigation and Positioning in Survey Missions where Navaids are Lean and Far Off
Authors: Sender Friedhelm
Published: October 2008

So far it is of little help for a survey navigator, that in the 80's satellite navigation systems on worldwide base will allow fixes continously in real time with an accuracy of ten to hundred feet.

Instead he has to cope with existing facilities still for several years. Especially on the southern hemisphere groundbased radio-navaids are rare and the Transit-Satellite-System allows its lowest sporadic fix frequency in the equatorian region.

This paper will present a survey of methods how presently available navaids maybe exploited to achieve optimal navigation and positioning results as they are needed for research-vessels in areas not covered by accurate radionavigation facilities.

Methods for improvement of groundbased radionavigation systems are discussed for exploitation of existing facilities beyond their normally useable range and to set up own navigational buoys at deep sea to obtain a continous real time position information.

INTRODUCTION

A considerable number of radionavigation systems and devices are scattered throughout the radiofrequency spectrum. The casual observer or even the scientist who has studied a particular system in depth may wonder why so many frequency assignments for navigation exist. The choice of frequency which basically defines the wave propagation mode is far from arbitrary, e.g. the particular requirement' for very long range navigation is met only by few propagation modes.

Accuracy of any system IS Inverse proportional to distance. This applies more severely to systems with complex wave propagation. It means that obtainable accuracy for very long range systems is largely an academic matter. In cases, where is no other choice even low accuracy "back Up" systems may be of enormous value also when the uncertainly is one mile or more.

There are only few radionavigation aids, which are useable for very long range operation. The most important are:Loran C, Omega and the Navy VLF Communication and Navigation Systems. Using these facilities the user has normally no influence to improvements of the transmitter systems. The only thing he can do is to evaluate his receiving and data handling equipment to harvest the full potential of obtainable information.If the user really needs more accurate information, he may obtain it by employing his own deep-sea navigational buoys for active and differential navigation.

Radio Propagation in General

Normally radio propagation is straightforward like visible light. This fact would make long range navigation along the earth surface impossible unless transmitter and receiver are elevated over the horizon. Beyond the horizon transmissions are feasible by four propagation modes.
The Role of Model Tests in the Design of Single Point Mooring Terminals
Authors: Pinkster J.A. , Remery G.F.M.
Published: October 2008

This paper gives a broad outline of model tests with single point mooring systems. This includes the purpose of the model tests, the information necessary to set up test programs, the scope of tests, the characteristics simulated, measurements carried out, possible sources of errors and the analysis of results. Furthermore, examples of test results are given which show phenomena characteristic of s.p.m. terminals. Finally, some of the phenomena observed during tests and a source of uncertainty in existing methods to calculate the behaviour of s.p.m. ship systems are discussed.

INTRODUCTION

Single point mooring terminals are, as the name implies, facilities of small horizontal dimensions, to which large vessels are moored by means of a bow hawser or by any other means which allows the vessel to rotate 3600 around the mooring point. Generally, the single point mooring terminal can have two functions. Primarily, it affords a safe mooring to the vessels in question. Secondly, it can form a link in the chain for the transport of oil.

The single point mooring terminal can assume many forms as is shown in Fig. 1. The most common is the Catenary Anchor Leg Mooring system (CALM) consisting of a flat cylindrical shaped buoy which is anchored to the sea floor by means of up to 8 chains. This system employs the properties of the catenary to supply the elasticity required when holding large tankers in open seas. The Single Anchor Leg Mooring system (SALM) consisting of a cylindrical buoy attached to a heavy base on the sea floor by means of a single pre-tensioned anchor chain, obtains its elasticity from the angle between the single anchor leg and the vertical. Enlarged version of the single point mooring terminal are the Exposed Location Single Buoy mooring (ELSBM) and the SPAR. The second of these does not only fulfill the function of mooring point and link in the oil transport chain, but is also used as a storage unit.

The types of mooring system described here, are excepting the ELSBM and the SPAR primarily used in water depths of up to approximately 150 ft. Some of the systems can with modifications be used for even greater water depths, however.

Rigid spar buoys connected to the sea floor by means of a universal joint are at present being designed. These consist of a buoy at the surface rigidly connected to a frame work which extends down to the base. This type of mooring is intended for water depths of 300 ft. or more. Finally, there are the mooring towers which consist of a slender open frame work fixed to the sea floor. Unlike all other systems, this type of mooring terminal does not contribute to the total elasticity of the system.

Generally, the tankers are connected to the mooring terminal by means of large circumference synthetic ropes which are part of the operating equipment of the terminal itself. In one case where the vessel is permanently moored to serve as storage space, the connection consists of a rigid arm.