bluuebunny/crossref_metadata_2025 huggingface dataset:
Hydrocarbons Under The Sea - A New Survey Technique
Authors: Schink David R. , Guinasso Norman L. , Sigalove Joel J. , Cima Norman E.
Published: October 2008

Hydrocarbons seeping from the sea floor can reveal the location of commercially significant offshore-oil and gas deposits. Such seeps produce a localized increase in the concentration of hydrocarbons dissolved in the adjacent sea water, but these concentrations will be transported and dispersed by marine currents and mixing. Calculation of the resulting concentration patterns shows that an optimum search requires sampling very near the sea floor. Equipment to perform such searches has been constructed and tested.

A submersible, pump is attached to special faired tubing containing hose and electrical and support cables. An automated winch deploys or recovers the hose and pump at survey speeds. Sampling can extend to depths of 185 meters at speeds up to 6 knots. Sea water from the pumping system is passed through a rotating disk stripper, where over 95% of the dissolved light hydrocarbons are removed by a counter-current flow of purified air. Total hydrocarbon concentration is measured continuously. Ethane, propane, and isobutane are collected, and six-minute integrated samples are determined continually. Sensitivity is sufficient to measure natural levels in the open sea. The system contains integral "blank" and "calibrate" functions and is designed to function automatically without constant operator attention.

Seeps Point the Way

Oil and gas seeps have helped to guide oil exploration ever since Drake drilled a seep area to the first producing oil well. Link (1952) prepared an extensive review of their types and locations and emphasized that they have provided the first clues to most of the major oil producing regions of the world. He showed that such features are widespread, numerous, and almost always found when there are major deposits. The Texas-Louisiana area is considered anomalously free of large seeps yet Link was able to locate more than 85 oil and gas seeps within 100 miles of the coast in those two states alone. Gas seeps of dramatic strength are well known.
Design And Actual Behavior Of Pentagone 81 Semi-Submersible Drilling Platform
Authors: Rey-Grange A.C.
Published: October 2008

The design of PENTAGONE 81 semi-submersible platform is based upon extensive model tests and uses advanced knowledge for computation.

Behaviour of the actual first unit was analysed and confirms satisfactorily the predictions.

Using statistical information treatment methods, it is possible to predict the behaviour of the unit or of similar units in any area.

Introduction

So called semi-submersible floaters are highly sophisticated compared with plain barges or even ships. They are also more expensive, because they are a lot more complex and have not as good a structure steel weight efficiency. But the offshore drilling industry is ready to pay for it since these floaters average a better overall economical cost per well in difficult seas, when they are not the only effective means for extreme conditions. Perhaps somewhat irrationaly for the very first units, their principle was settled when it was realized that an elaborated hull configuration was able to provide a better stability than a larger and heavier plain floater, over the minimum hull displacement governed by the cargo capacity.
Various Uses For The Articulated Column ELFOCEAN, A New Concept
Authors: de Chassy C. Bellon , Frankhouser H.S. , Picard J. Bellon
Published: October 2008

The articulated column, ELFOCEAN, has proven the feasibility and advantages of this new type marine structure. Installation of the column was performed without derrick barges or heavy equipment in the minimum time.

During the two year test period the column has behaved as predicted by calculations and model tests. This behavior confirms the application of the column for the drilling, production, storage, flaring, mooring and loading functions associated with offshore oil production.

Each use of the column was studied separately. Hence important technological problems, specific to each use, were solved. Studies which simplify the analysis and design for each specific case have been completed. Extensive model basin and field tests were carried out to check field behavior of the column with a tanker moored to it. The behavior and structural response of the column have been correlated with results of computer calculations.

Designs have been developed for water depths as great as 1200 feet for the various uses of the column.

INTRODUCTION

Since the mid-1950';s oil production has been moving into deeper and deeper waters. Costs of conventional, fixed bottom-supported structures have increased rapidly. Incomes from offshore fields have been correspondingly reduced.

There are several possible solutions to this problem. For instance, a conventional fixed structure could be used with the top of the structure submerged below the level of significant wave action. This would reduce both the overall size of the structure and the cost. But, operation and maintenance are apt to be costly with the top of the structure submerged, and the danger of pollution is greatly increased.

The articulated platform with an above water section provides a very realistic alternate solution, for water depths up to 1200 feet. To prove the acceptability of this new concept, a prototype was built. This prototype provided a full scale test model which was subjected to difficult test conditions.

For the past 2½ years the prototype articulated platform has performed very well in 328 feet of water in the Bay of Biscay. During this period the platform has been exposed to very severe sea conditions.

ELFOCEAN - Prototype of the Articulated Platform

A. Description

The experimental prototype articulated platform, ELFOCEAN, has been in continuous service since 1968. There-have been numerous articles in engineering and trade publications about the platform. Hence, only a brief description of the essential characteristics of the platform will be given.

The major component of the platform is a vertical cylinder 110 meters long and 7 meters in diameter. Atop this vertical cylinder is the cylindrical head which is 10 meters in diameter. A universal joint connects the cylinder to a rectangular gravity type base. The base is 21 by 24 meters and serves to hold the cylinder in position on the bottom. Buoyancy and lateral support for the cylinder are provided by six buoyancy chambers attached near the upper section of the cylinder.
Modeling of Pigging with Production Fluids in a Single Flowline
Authors: Dykhno L.A. , Hudson J.D. , Harris J.A. , Seay M.R.
Published: October 2008

Selection of a single flowline tieback subsea configuration with a reliable subsea pig launcher is often the most cost attractive option for deepwater developments. Pigging in such systems may be applied for de-watering during commissioning, for removal of untreated fluids after an unplanned shutdown, for wax removal, etc. Production fluids could be used in this case to propel the pig along the pipeline. This results in significant challenges in terms of pigging control and effectiveness. Furthermore, in many cases the pigging operation needs to aligned with other operations. For example, during start-up, fast ramp-up times are desirable in terms of hydrate management and chemical usege; however, without effective controls, the pig velocity will increase dramatically in the deepwater riser so that effectiveness may be compromised. Thus, controling the movement of the pig may prove quite challenging, but is aided by detailed transient analyses. The results of such numerical analyses (using OLGA-2000) will be presented in the paper. The simulations were performed to support system design and operations planning for a deepwater development. Optimization of process parameters are discussed along with the potential for topsides control.

Introduction

In terms of capital considerations, single flowline tiebacks are an attractive option for deepwater applications; however, a number of significant flow assurance issues remain to be addressed including:Maintaining the ability to sweep out residual water in the flowline during a cold restartThe ability to sweep low pH fluids out of the flowline after completion or stimulation activitiesThe ability to scrape deposits, such as paraffins, off the flowline wallThe ability to sweep fluids out for corrosion control (or to distribute corrosion inhibitor) during late life, should the lines begin to operate within startified flow regime.

Recently Shell has investigated technologies that could mitigate some of the above considerations. One technology is under consideration is the use of a subsea pig launching system that utilizes production fluids to propel the pig. A key added benefit of such an application is that production downtime is minimized during the operations.

There are several potential limitations of the application of these technologies to deepwater such us:Pig integrity and robustness - if application involves long term storage subsea;Design and feasibility of equipment and pigs for wax control applications, including the ability to conduct progressive pigging;Maintaining control of a pig being propelled by multiphase production fluids, particularly with respect to the risers and topsides onboarding facilities.

The latter aspect is under consideration in this paper.
Malampaya Deep Water Gas To Power Project - An Overview - Powering The Philippines Into The New Millennium
Authors: Greer David J.
Published: October 2008

The Malampaya Deep Water Gas to Power Project (the Malampaya project) reached a major milestone when the Declaration of Commerciality for the project was signed in May 1998. In just less than 31/2 years, Shell Philippines Exploration B.V. (SPEX), as Operator, successfully completed this remote deep water gas project, and successfully accomplished two additional major milestones by landing gas for power plant commissioning to its downstream buyers by October 1st 2001 and commencing commercial sales deliveries shortly thereafter on January 1st 2002.

This paper describes the history behind this landmark undertaking, the trade-off between alternative deep water development solutions, the contracting strategies employed as well as the many venture management, technical, HSE, commercial and sustainable development challenges that were undertaken by SPEX to successfully transform this exciting deep water project from a vision into a reality.

The Malampaya project marks the dawn of the natural gas industry in the Philippines, illustrating the crucial importance of integrating the development of gas markets with the rapid construction and successful operation of the necessary deep water and onshore infrastructure. The Malampaya development comprises five novel subsea wells in 820 metres of water, producing via a subsea manifold and two 30 km long, 16 inch flowlines to a concrete gravity platform located in 43 metres water depth. These wet gas flowlines, with their large vertical displacements and mixture of gas and liquids have pushed deep water subsea gas development technology to higher levels. The platform production facilities were installed on a concrete gravity substructure that was built in Subic Bay, Philippines and completed some 3 months ahead of schedule. The topsides facilities were fabricated in Singapore and were towed over 2200 km to the Philippines on March 1st 2001. The gas and condensate is treated on the platform to export specification. Gas is compressed and transported via 504 km long 24 inch pipeline to an onshore gas plant at the site of the Shell Refinery at Tabangao (Batangas, Luzon Island). The condensate is stored in the platform concrete substructure caisson and exported approximately every two weeks via shuttle tankers. The Malampaya pipeline is a major engineering accomplishment in its own right, traversing rugged sea floor topography through seismically active and environmentally sensitive regions. An onshore gas treatment plant, built to remove the H2S content of the gas will serve as the delivery point to the buyers.

The project schedule to meet the 1st October 2001 first gas flow commitment to the gas buyers was very tight from the outset. The project goals were achieved by continued attention to the six project tenets of cost containment: schedule attainment, use of innovative technology, high system availability, exemplary Health, Safety, Environment and Security (HSES) management, and Sustainable Development.
Malampaya Deep Water Gas-to-Power Project: Malampaya Subsea Development
Authors: Seaver J.
Published: October 2008

The Malampaya field development comprises subsea wells in 820 metres water-depth producing via a subsea manifold and two 16 inch diameter inconel clad flowlines to a shallow water platform 30 km distant in 43 metres water-depth. Condensate is removed on the platform and the dry gas is then transported via a 504 km long 24 inch export pipeline to an onshore gas plant for at Tabangao (Batangas, Luzon Island) for extraction of H2S. The condensate is stored in the platform CGS caisson prior to export via a short 3 km long 24 inch diameter pipeline and CALM buoy (Fig. 1).

The Malampaya development is unusual insofar as it is in a remote deepwater location offshore the Philippines and utilises subsea wells as the sole supply of gas to electricity power generation stations located on the mainland. Many challenges had to be overcome to realise this latest advance in the development of deep water subsea production capability:High reliability and system availability requirements;Difficult flow assurance aspects including hydrate prevention and high liquid hold-up in the flowlines;High production rate wells, high H2S and CO2 content of produced fluids requiring CRA materials;Installation and operation in a remote location devoid of the customary support infrastructure.

The Subsea System design focussed on achieving the highest levels of overall system availability. This was achieved by a combination of simplifying the design where possible and providing suitable levels of redundancy. Thisapproach was supplemented by applying the highest levels of quality assurance and control during the manufacturing phase. Finally, a full system integration test was undertaken prior to installation offshore to simulate the in-service conditions and verify the system performance.

This paper describes how these unique challenges were addressed during the realisation of the Malampaya Subsea System.

Introduction

The Malampaya Subsea System consists of a 10-slot subsea manifold with the wells positioned on both sides of the manifold (Fig. 2). The wells are tied-in to the manifold using rigid tie-in spools and separate flexible "flying leads" for providing electric and hydraulic control to each well. The two 16 inch dia flowlines are connected to the subsea manifold using rigid tie-in spools approximately 50 - 65m in length. The flowline tie-in spools are designed to accommodate the thermal expansion at the ends of the flowlines of approximately 2m. Electric and hydraulic control, methanol injection and annulus venting capability for the Subsea System is provided by two subsea umbilicals tied-in to the subsea manifold. The capability to tie-in the third 16 inch dia flowlineis provided by using a "tap it later" tee located on the subsea manifold. The capability to tie-in a third subsea umbilical to the manifold is also provided.
Spoolable Bonded Flexible Pipes for Gas Service
Authors: Antal Sándor , Nagy Tibor , Grépály István
Published: October 2008

The paper describes the key properties of the bonded flexible pipes, including the recent development of bonded flexible pipes; especially for choke and kill systems as well as for continuous high pressure gas service. The construction and the qualification procedures acc. to API specifications 16C [1], 17K Draft5 [2] and RP 17B [3] are discussed. An interesting application example is introduced, which is believed to be the first integrally floating high pressure line for live crude oil. The advantages and limits of the bonded flexible pipesare presented.

Introduction

The oil industry uses large quantities of flexible pipes, basically for offshore oil drilling and production, but frequently onshore as well. Their onshore application can be explained with the possibility of easier assembly and the unequal subsidence of the equipment due to the production, but for offshore production in many cases there is no other solution at all. The connection between the fixed equipment placed on the seabed and the floating drilling or production units can only be achieved by flexible pipes. There are two basic flexible pipes: "unbonded flexible pipe" described in API (American Petroleum Institute) Standard 17J [4] and "bonded flexible pipe"; at the date of submission of the manuscript the relevant API 17K Standard is in Draft5 stage [2].

The unbonded flexible pipe construction consists of separate unbonded polymeric and metallic layers, which allows relative movement between layers. In the bonded flexible pipes the steel reinforcement is integrated and bonded to a vulcanized elastomeric material. Both constructions are spoolable; the bonded construction is generally used in short lengths up to 30-40 m, but it is available upto 200 m single pieces. Longer lines can be assembled with intermediate couplings.

The bonded flexible pipe is a very special composite structure, where the reinforcing material is steel cable or wire laid in specific angles and the continuous phase is rubber. The modulus difference between the reinforcement and the continuous phase is much bigger than in any other composite, 5 orders of magnitude. This results in unique properties of bonded flexible lines.

The flexible lines are used in numerous applications e. g. as rotary drilling hoses, choke and kill lines, production flow lines, gas or water injection, pile driving etc. In the present paper we focus our attention to those applications, where the lines are exposed to high pressure gas service. This is the case with choke and kill lines intermittently, and with production, gas injection and gas export lines continuously. The experiments were carried out on particular design of cable reinforced flexible pipes. More details can be found in references [5;6;7;8;9]. Since bonded flexible pipe manufacturers use different components, coupling designs etc. special care had to be taken in generalization of the statements, especially if the reinforcing material is solid wire, not cable.
Potential Hydrocarbon Plays of the Gulf of Mexico
Authors: Lowrie Allen , Somoza Luis , Gardner Joan M. , Klekamp Thomas L.
Published: October 2008

Due to a complex geologic evolution, the Gulf of Cadiz hydrocarbon province contains a complex petroleum system. North Atlantic rifting caused deposition of sedimentary sequences that show a progression of facies from riverine to lacustrine to evaporites to marine sediments. Concomitant tectonically induced basin subsidence occurred as rifting progressed. The Alboran Domain, underlying the present Alboran Sea, began moving westward from western Mediterranean in the Miocene as result of the northwesterly compression between the Iberian and African plates forming the Gibraltar Arc.

Westward crustal motions caused serial events: upper slopeover steepening triggered major mass-wastings to descent some 500-600 km downslope forming the accretionary wedge of the Gibraltar Arc. Simultaneously, subshelf basins developed and were infilled with material from the nearby shelf and Guadalquivir Basin-river system. Across the continental margin, extension occurred over the upper slope and compression along the lower slope.

1.0 Introduction

The Gulf of Cadiz continental margin has been proposed as a potential world-class petroleum province1, 2. The margin is a known hydrocarbon producer with largely biogenic natural gas extracted under the continental shelf1 Abundant evidence exists for pockmarks, i.e., mud volcanoes with natural gases sampled from them (research conducted by Joan M. Gardner and Luis Somoza, 2000 and 2001), along the upper and middle continental margins off the Gulf of Cadiz and Morocco). Thus, these margins are undeniably petroliferous.

A complex tectonic history beginning with the Triassic-Jurassic North Atlantic rifting to the present3 has resulted in a complex petroleum system,1 based on sizable seismic data sets, including high and low frequency lines. Figure 1 is the location of industry-quality data. These lines were collected in he 1970s and 1980s by industry for hydrocarbon exploration. The data set spans the continental shelf, the upper slope, and the down-to-middle slope in water depths up to 1000 m.

The overriding geologic problem is that the measured geothermal gradient along the shelf (2.4°/100 m) is too low to cause a hydrocarbon column that has been reported to be some 2.0 to 2.5 s two-way travel time (t-wtt) thick1 (also see Figs. 2, 3, and 4), with sediments extending to depths of 3-3.5 s, apparently interspaced between rising (from east to west) thrusts of continental rocks. The actual sediment thickness may reach 4 to 6 km, possibly even 7 km at maximum depths beneath the thrusts1,2(Fig. 2).

Figure 3 shows that with basement thrusting from east to west, the thrusts may override thin (< 100-200 m thick) sediment wedges (Fig. 3a) and that advancing thrusts impact the sediments, initiating fracturing deformation of the thrusts (Fig. 3b). Continued thrusting heavily fractures the sediments, shattering them; fractures possibly radiate from the advancing thrusts for a distance equal to the thrust diameter (Fig. 3c).
Ceiba Field Development Project Execution
Authors: Brashier Robert S. , Pavia Anthony P.
Published: October 2008

This paper will describe the project organization, methods, philosophy and execution used to develop the Ceiba Field; a fast track, two phased, subsea tieback to an FPSO, offshore Equatorial Guinea. It will detail the advance planning that was done by Triton Equatorial Guinea, Inc. (acquired by Amerada Hess in August 2000), the engineering study performed for Ceiba, the process by which primary contractors were selected and how the coordination of various aspects were handled. The paper will discuss the installation of the early production system and startup of the field in less than 14 months from discovery and subsequent expansion of the system in the following 14 months.

Introduction

Triton discovered the Ceiba Field in October 1999 in the previously under-explored Rio Muni Basin in the Gulf of Guinea, offshore Equatorial Guinea. Following the discovery well, Ceiba-1, and drilling of the confirmation well, Ceiba-2, Triton embarked on an aggressive development with prudent risk management to achieve first oil production in a record setting 14 months from discovery. (Figure 1)

The Ceiba Field development was implemented in two phases. Phase 1 is an early production system whereby four subsea trees and manifolds are tied back to a spread moored FPSO in shallow water. Water depth at the FPSO location is 90 meters and approximately 700 meters at the subsea wells. Each Phase 1 well is tied back to the FPSO via dual 8" insulated steel flowlines with flexible jumper connections to the manifolds. Flexible risers from each flowline are supported by a riser support structure (RSS) set on the seabed adjacent to the FPSO. Separate multifunction control umbilicals are routed along the flowline routes to the individual manifolds withintegral subsea distribution units (SDU).

Phase 1A was implemented in parallel with Phase 1. While Phase 1 equipment was being fabricated and installed, Phase 1A engineering, design and start of manufacture was in process. Phase 1A added two, four well production manifold systems; three, four well water injection manifold systems; and one satellite water injection well. Production manifolds are tied back to the FPSO with dual 10" flowlines. Water injection manifolds are tied back with single 10" flowlines. Additional processing capacity on the FPSO for production and water injection was accomplished by changing out the FPSO rather than adding process modules in the field. Phase 1A start up occurred 14 months after the Phase 1 first oil milestone.

Ceiba Development

Early Planning and Conceptual Engineering

By the end of the first quarter of 1999, Triton had assembled a multi-disciplinary team of exploration and operations personnel to develop a plan for drilling and appraisal of Triton's license acreage in Blocks F and G. Concurrent with the exploration team work, early in-house conceptual engineering work was done with cost estimating software and information in the public domain. This work helped to evaluate possible development concepts and was incorporated into project economics.
Ceiba Field Operational History
Authors: Hopkinson J. Michael
Published: October 2008

This paper describes the operational history for the Ceiba Field. The FPSO vessel and process equipment is detailed together with external support required for servicing the facility and exporting crude oil. Areas of particular interest including operational problems and the related solutions are also detailed.

Introduction

The Ceiba field, offshore Equatorial Guinea, West Africa was discovered in October 1999. The water depth at the field is approximately 700m. Development of the prospect started immediately leading ultimately to fist oil being produced from four subsea wells tied back to an FPSO approximately 5 miles distant. Hydrocarbons were first received on the FPSO Sendje Berge on November 22nd, 2000, fourteen months after discovery. To achieve this difficult task many engineering judgements were made with a view to maintaining flexibility of the surface and subsea systems in the future. The following paper describes the operational history together with the steps that were taken prior to production to maximize production uptime.

The field to this point has been developed in two phases. The first phase is namely "Phase 1" which includes wells Ceiba 1, Ceiba 2, Ceiba 3, Ceiba 4 and Ceiba 7. The second phase "Phase 1A" includes additional production and water injection wells. Part of the Phase 1A development inclided changing out the existing FPSO for an upgraded FPSO.

Facility Description

The FPSO Sendje Berge is a VLCC (Very Large Crude Carrier) taken from the Bergesen shipping fleet and converted to an FPSO by adding process facilities and modifying the ships systems. The FPSO was moored in position using twelve pre-installed anchors. Production from subsea wells was routed to the FPSO from the wells via 8" flowlines and flexible risers to compensate for vessel motion.

Production history from the field aided in the specification and construction of a modified vessel (FPSO Sendje Ceiba) and ultimately the replacement of the Sendje Berge with the Sendje Ceiba.

Production Statistics

Ceiba first oil was on November 22, 2000. Since first oil, up until January 12, 2002 when the Sendje Berge was changed out for the Sendje Ceiba, 13,014,182 barrels of oil have been produced and exported. Nineteen export operations were conducted using a bow to bow transfer method. All produced gas that is not used as fuel gas is flared. Produced water is treated on board to reduce hydrocarbon content and insure that environmental criteria are met before being discharged overboard.

The average facilities uptime for the 14 months that the Sendje Berge was producing was 98.73%.

Bergesen Offshore provided the marine crew on board the Sendje Berge. The crew is responsible for maintaining the ship's facilities including steam used for crude heating, generation of electrical power and exporting operations. Approximately sixty people are regularly stationed on the Sendje Berge to provide this support. ABB Offshore provided the personnel to support the process facilities, a total of 10 make up the compliment of production crew.
A New Solution for Tandem Offloading of LNG
Authors: Eide Jorgen , Eide Svein I. , Samuelsen Arild , Lotveit Svein A. , Aanesland Vidar
Published: October 2008

Many oil companies presently work on plans for production of Liquefied Natural Gas on a Floating LNG Production and Offloading (FLPO) vessel. All these schemes require suitable systems for offloading of the LNG to a transport tanker.

Safety and regularity are important issues in design of offshore LNG production and loading systems. In addition to the offloading operation the tanker approach, connect, disconnect and departure phases include critical operations which are weather dependant and may impose restrictions on operability and regularity.

The OCL system is a stern to bow, crane and flexible pipe solution that is developed, based on extensive experience from tandem offloading operations of crude in the North Sea in harsh weather conditions. The system is well suited for LNG transfer where high regularity is required and a large number of cargoes are shipped every year.

The LNG tankers are dedicated transport vessels with modifications in the bow to suit purpose built hawser and loading facilities. When offloading the LNG carrier in a harbor a conventional LNG manifold offloading system in the center of the LNG tanker is used.

In offshore loading, the two vessels are moored together in a "crowfoot" hawser configuration reducing the relative movements between the crane tip on the FLPO and the bow of the tanker. The LNG carrier is operating on constant stern thrust to ensure the required stability of the offloading system in both calm and harsh weather conditions.

Components and sub-systems are selected on basis of functional requirements. Critical components have been qualified in a step-by-step process. The qualification includes development of mathematical tools that have been verified through material testing, model testing and full scale testing. Verification includes design, manufacture and testing of the complete pull-in and connection system as well as full flow testing.

Figure 1 - The OCL LNG transfer system(available in full paper)

Vessel model testing is used both as verification and calibration of the mathematical models and it ensures accurate calculation of the two vessel's motions in the loading area and thus good prediction of the loads on the transfer system.

The flexible pipe is the most critical part of the transfer system. The OCL system is based on a longitudinally welded, thin-wall stainless steel tube corrugated to provide the required bending flexibility. The finished flexible transfer pipe is a lightweight, double-wall construction with vacuum in-between the pipes as thermal insulation.

The qualification process includes full-scale flow testing with both water and LNG. All tests and calculations show that the described solution will allow safe and economic transfer of LNG from a floating production vessel to a tanker.

The OCL LNG transfer system will allow development of stranded gas reserves in areas with no infrastructure, or where a pipeline to a shore facility is not viable or economical.
Classification of LNG FPSOs - A Viable Route For Risk Management
Authors: Ramberg Liv Anette , Skramstad Erik
Published: October 2008

Floating concepts for LNG production and LNG terminals are being evaluated by the industry to meet the increasing worldwide demand for LNG as a clean, environment friendly energy source. Novel technical solutions are required to enable commercially viable developments of remote resources, marginal fields, utilization of associated gas and to provide increased terminal capacity. These new concepts involve a large number of technical uncertainties, large investments and large perceived hazards and this requires effective risk management. In response of this DNV has developed a classification approach for LNG FPSOs, aiming at provision of a structured and predictable assessment of novel concepts.

These classification services and rules for LNG FPSOs draw upon the long experience with risk management of gas carriers and oil producing FPSO's. The classification approach utilizes the best practices both with regard to traditional codes and standards, industry practices as well as use of quantitative risk assessments for decision support among technical alternatives, and qualification procedures for new designs.

Introduction

The demand for natural gas is increasing on a world-wide basis as a result of the increase in the worlds energy consumption, and environmental concern.

Among the fossil fuels available today, natural gas is by far the most clean and environmentally friendly energy source. LNG represents today the most efficient commercial handling and long distance transportation of natural gas.

Floating production of LNG will allow development of remote gas fields and utilisation of associated gas from oil production. Several concepts have been developed recent years concluding feasibility from an economical, technical and safety point of view.

Common to these concepts are that they represents new solutions which not yet have been proven in practice. The following issues represents particular challenges both with respect to the safety for personnel, vessel as well as functional requirements:A highly complex and compact process plant installed in a limited area.Storage of LNG in the proximity of Process equipment and Accommodation.Cargo Transfer in open seas.

Key objectives in the design must be toensure reliable operation.offer adequate protection of personnel including means to ensure safe evacuation and escape.minimize the risk for massive release of LNG from the cargo tanks which can develop into catastrophic scenarios resulting in total loss.

The latter implies that focus must be given to all events with the potential to damage the tanks e.g.escalation of process events to the storage tanks (fire, explosions, dropped objects)tank integritycollisionshull damage, flooding and stability

DNV has identified LNG FPSOs to be an area where we can contribute to our customers needs and demands and we have developed new rules for the Floating LNG/LPG Production storage and offloading units. For this purpose a new class notation was launched in 2001.
Vertor Fidelity Assessment From 4C Seismic Data Recorded on the Seafloor
Authors: Granger P-Y. , Meunier J. , Gratacos B.
Published: October 2008

Vector fidelity is essential for all processing methods dealing with multi-component data and based on elastic wave propagation. However, fidelity cannot be simply assumed: lack of fidelity can introduce severe errors at the early stage of processing the horizontal components. The position of this paper is that there is enough redundancy in the acquired seismic data in order to control the vector fidelity, and when needed, correct for possible departures. The paper analyzes the various causes of vector infidelity and describes practical methods to correct for it.

Introduction

Vector fidelity refers to the ability of the seismic system to reproduce in a faithful manner the particle movement at a precise place and under the excitation of a well-known source. Because vector fidelity is not easy to achieve (especially for the horizontal components) its impact on the final seismic images and results should not be underestimated. Vector fidelity QC is therefore a mandatory step of the processing flow. Vector fidelity depends on many factors related to source, receivers and the experimental conditions. Likewise, measurement and possible departures from fidelity can be corrected in various ways. A check of the required source symmetrical radiation pattern is among the first steps of the QC flow. While it can be assumed that errors in the source position are negligible, an important task is to check the positioning of the recording geophones and to ensure that the three components are along the desired vertical and horizontal directions. Under the hypothesis of a mechanical isotropic device, a fundamental QC step is to verify that the seismic response of one of the horizontal components is not biased with respect to the other. Indeed, poor receiver coupling to the sea floor affects the accuracy of the recorded data and induces differences between the inline and cross line responses of the horizontal components.

It is common practice in our industry to use the seismic data themselves to control the various parameters of the seismic measurement. Indeed, the redundancy contained in the seismic data is so high that it is sometimes possible to compensate for even severe departures from vector fidelity. This paper describes our understanding of the behavior of the various systems deployed on the sea floor and the methods we have developed and that we routinely use in the first steps of the processing flow.

Source directivity

It is well known that the source arrays used in standard streamer acquisition are in general non isotropic and compensating for a possible asymmetry of its directivity pattern is not an easy task. When such a source is used in 4C operations the possible asymmetry in the directivity pattern affects mostly the acoustic direct arrival. The main consequence is the possible impact on the various steps that involve that arrival. However, a possible asymmetry affects mostly the spatial distribution of the direct arrival.
Deep Ocean Mining - New Application for oil Field and Marine Equipment
Authors: Lecourt Everett J. , Williams Darrell W.
Published: October 2008

The first attempt to mine manganese nodules in a deep water environment was successfully accomplished during the summer of 1970 in the Atlantic Ocean. The conclusion of this prototype test established a significant milestone in man';s attempt to commercially mine natural resources from the ocean floor.

During the thirty day operation on the Blake Plateau, significant tonnages of nodules were pumped through 9 5/8 inch O.D. pipe in 2,500 feet of water. Pipe strain, air-lift pumping data, and ship motion were monitored and recorded by engineer and technicians throughout the operation.

The primary purpose of this paper is to describe some of the operational techniques and equipment used on the which was converted from a type cargo ship. Nearly all of the shipboard equipment was originally developed for the marine or oil industry. - Major components which are described in the paper include:shipdredge pipepipe handling equipmentpumping system andinstrumentation.

The information gathered from the prototype dredging test confirmed that new technology combined with conventional equipment can be used to permit the commercial hydraulic dredging of deep ocean ore deposits.

Introduction

"....the final success of underwater mineral exploitation lies in imaginative, thorough development of conventional engineering techniques rather than in new and highly sophisticated devices." That statement, made by John E. Flipse in his paper in 1969, reference I, expresses the basic philosophy which was followedin the design and construction of the first deep ocean prototype mining vessel - R/V DEEPSEA MINER.

This vessel was used to recover manganese nodules in 2,500 feet of water on the Blake Plateau. Although the nodules in this area lacked sufficient assay value to be mined and processed commercially, the general area provided an excellent proving ground for testing recovery techniques. The remainder of this paper will describe the marine and oil field techniques which contributed to the successful completion of the prototype test.

Prototype Mining System

The prototype mining system utilized a pipe suspended from a ship in 2,500 feet of water. The nodules were entrained in seawater and pumped to the surface through the dredge pipe. A separator on the ship separated the nodules from the water, and the nodules were dropped onto a belt conveyor which dumped them into a storage hopper.

The method of pumping used in the test was an air-lift system. Flow in the pipe is induced by continuous injection of air into the pipe at a depth of 1/3 to 1/2 the depth of the ocean.
Response of Topside Structures to Fires and Explosions: Design Considerations
Authors: Burgan B.A. , Hamdan F.H.
Published: October 2008

The design of topside structures to resist hydrocarbon fires and explosions necessitates consideration of a range of issues not normally addressed by the designer. This paper gives an overview of the key issues that have been studied in several sponsored R&D projects and by the Fire and Blast Information Group (FABIG). The results are presented in a form that is usable by designers. The main areas covered are:Elevated temperature material property design data for use in fire engineeringHigh strain rate material property design data for use in explosion resistant designAnalysis techniques for fire and explosion designDesign methods based on codified rules (i.e. covered by design standards) and advanced techniques

Introduction

The design of North Sea topside structures to resist fire and explosion scenarios received greater prominence since the late 1980's. Numerous joint industry projects were undertaken to better understand the characteristics of hydrocarbon fires and explosions, and the way topside structures respond to such events. In 1992, the Fire and Blast Information Group (FABIG) issued the 'Interim Guidance Notes for the Design and Protection of Topside Structures' (IGN's) [1], the first comprehensive design document to deal with these issues, and this subsequently became the de facto design standard.

Since then, FABIG has issued 7 Technical Notes to supplement the IGN's. These have been distilled from the large number of joint industry projects completed in the 1990's. This work continues with plans now in place for a number of future Technical Notes and new projects identified to generate the background work for other Technical Notes.

This paper draws on the work of FABIG to give an overview of the technical issues that need to be considered by a structural engineer when designing topside structures to resist fires and explosions. In particular, the paper considers the role of advanced and simplified methods, and discusses the input requirements for these methods, especially with respect to appropriate material data.

Design Considerations for Topside Structures Subjected to Fire

The design of topside structures to resist hydrocarbon fires necessitates an understanding of the following issues:Nature of the fire load and how it impacts on the structure (i.e. identification of the nature of the fire, where it will burn, the thermal load generated by the fire and the temperature rise in time of the affected structural members)The performance requirements of the structure (e.g. strength, deformation limits, load shedding, etc.)The response of the structure when subjected to the received heat loading.

Fire Load Characteristics

A number of researchers have studied the nature and evolution of hydrocarbon fires [2,3,4,5,6]. Methods for converting the thermal loading from the fire into a received thermal load acting on the structural members, and subsequently into a time-temperature curve for each member are also available in the literature [7,8] in a form suitable for use in design.
Health and Safety Performance of the Global E&P Industry 2000
Authors: Smith Don
Published: October 2008

The International Association of Oil and Gas Producers (OGP) has been reporting the safety performance on behalf of the upstream oil and gas industry since 1985. Over that period there has been a significant reduction in the fatal accident rate (FAR) and improvements in the lost time injury frequency (LTIF).

In an effort to protect and improve the health of its personnel, the industry has, for the first time, started to collect more detailed occupational illness data from its operations around the world.

This paper presents the results from the year 2000 occupational injury and illness data collection programmes. The main database for this period represents over 1.6 billion hours worked, an increase of 36% compared to the 1999 dataset. Thirty-nine companies contributed safety performance data, from operations in 71 countries. Eight organisations responded to the call for occupational illness information, providing 235 million workhours of data.

It is shown that although there has been an increase in the total number of reported fatalities, the FAR remains similar to previous years due to the increase in the number of working hours reported. The LTIF has continued to show improvements compared to previous years, with the year 2000 data showing the lowest value recorded to date.

The most common types of incident leading to fatalities were vehicle related incidents, and persons being struck by moving or falling objects.

The first year of collecting detailed occupational health data has highlighted a number of problems which will need to be addressed in order to improve on the consistency and volume of this potentially valuable dataset.

Introduction

The International Association of Oil and Gas Producers (OGP) has, since 1985, been collecting and reporting the safety performance on behalf of the upstream oil and gas industry through its annual publication 'Safety Performance of the Global E&P Industry' [1].

This series of reports serves a range of purposes. Firstly, it presents to the widest audience possible how the industry has performed, year on year, on a range of key safety measures. Secondly, it allows E&P organisations to benchmark their performance against that of their peers. Thirdly, it assists the industry to identify areas where it may need to concentrate effort (eg driving related incidents).

Occupational Injury Data.

In the past, the main focus has been on collecting and reporting accurate occupational injury data and statistics. This has, in part, been driven by the relative ease with which injury related data can be collected and analysed, and the industry's, regulators' and public's desire to use such statistics as the primary vehicle for measuring the safety performance of the industry.

Over the years standard definitions of the main parameters which need to be reported have been developed. This has helped to minimise problems associated with organisations reporting injury related data based on a range of definitions.