bluuebunny/crossref_metadata_2025 huggingface dataset:
lntroduction to the Troll Project
Authors: Wheeler Peter J.
Published: October 2008

This paper sets the scene for six other papers to be presented at the joint Shell-Statoil session at the 1997 OTC Conference. The subject for this session is the Troll Phase I Gas ExportProject, for which A/S Norske Shell was the Development Operator, and Statoil is the Production Operator.

The Troll gas development consists of an offshore platform standing in 303 metres of water connected by twomulti-phase pipelines to an onshore gas processing facility, which can export up to 100 MM Sm3 and 3500 m3 condensate per day.

The paper briefly traces the history of the Troll field development from the discovery of the field in 1979, through to the establishment of the major design solutions. The first crucial development decision was to utilise on-shore gas processing, and the background to this decision is examined. In particular, the concept of utilising carbon steel multi-phase pipelines to transport the wet, untreated gas, is described. Anticipated benefits, relating to safety and environmental considerations, as compared to an integrated offshore facility, and the realisation or otherwise of these, are discussed.

The offshore and onshore facilities are described, and the major design decisions that they represent are highlighted. In particular: the satisfying of the offshore power requirements from the national electrical grid and the use of variable speed electric motors for driving the gas export compressors (subjects covered more comprehensively in another paper); the provision of the necessary fibre optic link from the platform to the onshore central control room to enable the offshore facilities to be operated from onshore; the use of air to satisfy process cooling requirements and hot oil for process heating needs; the use of a High Integrity Pressure Protection System (HIPPS); the use of an semi-automated, packaged drilling rig; and the extensive use of composite materials. These features represent design decisions which, are at least to some degree, counter-intuitive, and are reviewed specifically with respect to their contribution to overall environmental and safety objectives.

Introduction

The Field. The Troll field is located about 85 km north west of Bergen on the west coast of Norway, (fig. 1) in the Norwegian Trench, at a water depth of 303.4m MSL. The field was discovered in 1979 by AlS Norske Shell, operatorfor Production Licence 054 covering Block 31/2. In 1983 this Block was declared commercial. Also in 1983, the adjoining blocks 31/3, 31/5 and 31/6 were awarded under Production Licence 085. Subsequent drilling ascertained that Troll extended into all four blocks (fig. 2). This initiated a process of unitisation of the two licences. By the end of 1986 the individual shares of the various companies with interests in the four blocks were recalculated for Troll as one single field. The shares of the Troll Partners were established as follows:

(available in full paper)
Description and Application of New Criteria for Casing Setting Design
Authors: Lage Antdnio Carlos V.M. , Nakagawa Edson  Y. , Rocha Luiz  Alberto S.
Published: October 2008

Introduction

New well design and drilling follow-up methodology, based on a modified kick tolerance margin, was developed and successfully applied to the execution of six deep water and five high temperature, high pressure (HTHF') exploratory wells. This approach considers the whole scenario in a more realistic way, assuring safe and cost-effective operations. This work makes a review of current methods, introduces the new one and presents three case histories, two in deep water and one in a HTHP environment.

In the first case, well PAS-25 at a water depth of 1214m, the application of the new methodology made possible to eliminate an entire casing string, bringing about considerable cost reduction. In the second case, well CES-Ill, it was observed that friction pressure loss through the choke line (FPLCL) was very restrictive, requiring special attention during kick tolerance calculations. Finally, the proposed casing setting depth design and follow-up methodology was applied to plan BSS-78, a HTHP exploratory well of Santos Basin, southeast coast area of Brazil. This plan was based on data from a problematic reference well, BSS-70. The obtained results show significant economic advantages.

As a result, the experience from these field applications indicates that:the determination of reliable pore pressure and fracture gradient curves is critical for planning and execution purposes;specific drilling and well control procedures have to be defined, based on how critical is the well under consideration; andrigorous training program is necessary for the whole team.

Introduction

In 1993, PETROBRAS undertook various exploratory deep water drilling activities on the north and northeast of the Brazilian coast area. This campaign has required better engineering and the most advanced tools for well design. Some aspects, closely related to the deep water scenario, as:low fracture gradients; andhigh FPLCL, were very restrictive.

In such conditions, conventional casing setting depth criteria would be cost prohibitive and would greatly reduce chances of reaching the target, mainly due to bore hole size constraints. On the other hand, as Dynamic Positioning Drill Ships (DPDS) have drilled all of those wells, operational requirements of riser safety margin' would not allow to drill even the shallowest of the water depth wells in the series (746 m). These limitations have motivated the pursuit of a better understanding of the kick tolerance methodology, a key factor for changing the well project routine.

After a worthy experience in deep water, the planning approach was also successfully applied in HTHP wells, with the following main difficulties:rapidly rising pore pressure profile;convergence of pore and fracture gradients; andlong sections of open hole.
Albacora Field FPS: Another Deepwater Development Offshore Brazil
Authors: Awad S.P.
Published: October 2008

The Albacora field, one of the huge deepwater fields at Campos Basin, has been on stream since 1987 with a step phased development strategy, using early production systems. Undergoing phase I1 will use two floating production units, a semi-submersible and a FPSO, each one capable to process 100,000 bopd. This paper presents the Albacora deepwater field case study, stressing the evolution of the field development evaluation studies and highlighting the project milestones, as the Petrobras 25 FPS conversion, the diverless manifold design and installation, the rig allocation strategy and the well completion and tie in techniques, describing also the world record breaking subsea well ESP installation to be performed in 1,100 m water depth, among others.

Introduction

The Albacora complex is located 107 km off Rio de Janeiro State coast, in the northeastern part of Campos Basin, being discovered in 1984 at 293 m water depth. Appraisal wells in the following three years had confirmed the field extension into deeper water depths. It covers an area of nearly 235 km2 and can be divided in two distinct fields, Albacora and East Albacora, as oil properties and reservoir characteristics vary significantly (Fig. 1).

Recoverable reserves of the Albacora field are 665 million barrels of 26 to 29' API oil and 13.5 billion std m3 of gas in water depths varying from 230 to 1,000 m, while the East Albacora field shows 41 5 million barrels of 15 to 20' API oil in water depths ranging from 1,000 to 2,000 m. A total of eight different oil reservoirs are found in the Albacora complex from Tertiary (Oligocene, Eocene and Miocene) and Cretaceous (Albian) sandstone layers.

Phased Field Development

While developing production technology with an aggressive R&D program aiming to reach the 1,000 m water depth target, the plan was to bring on stream the shallower portion, at that time considered to be deep, of the Albacora field through a pilot system. Clarifying geological, reservoir and production uncertainties, and also generating early cash1 flow to support the next steps were the main goals.

The pilot system, consisting of six wells connected to a diver assisted manifold producing to a FPSO and a monobuoy, started production in 1987 and it is known as Albacora Phase I. The six wells were completed with lay away christmas trees in water depths ranging from 252 to 419 m. The FPSO was moored at 230 m water depth, being rigidly connected through a yoke to the monobuoy, exporting the production with a shuttle tanker tied to a second monobuoy. Peak production achieved 18,000 bopd and 0.25 million std m3/day of gas.
Campos Basin - 20 Years Project Managing Challenges
Authors: Maselli Alfredo S.S , Cavalcanti Renata B.
Published: October 2008

This paper presents, from a managerial standpoint, PETROBRAS' experience in the management of several projects implemented for the development of Campos Basin, offshore Brazil, as well as the evolution of the applied technologies.

Campos Basin

Located southeast offshore Brazil, it is the crude most productive site of the country.

The development of Campos Basin allowed Brazil to largely increase its crude production.

Today, Brazil's crude production is around 900,000 bpd, 625,000 bpd (70%) of which come from Campos Basin (data acquired in December/96).

Campos Basin was discovered in 1974 through the pioneer well RJS-9, located in Enchova Field. In 1976, production started in this field, utilizing a semi-submersible type structure (SEDCO 135-D) in a water depth of about 115m, flowing the production to a storage vessel moored on a square point system.

After this, more wells drilled enabled PETROBRAS to outline the fields boundaries resulting in a thorough planning to exploit the Basin. This planning splitted the area into two poles: North Pole and South Pole. The concept was to gather the production of each pole in one central platform and from there send it to shore. This concept envisaged to optimize the use of equipment and flowlines and, consequently, to reduce the cost of the installations.

By late 1978, a second production system went on stream at Garoupa field, utilizing a FPSO (a process ship - P. P. Moraes) moored to a process tower with a yoke type structure. The process tower gathered the production of 9 satellite wells and flowed it to the process ship through a swivel connection.

Following the development of the Basin, the installations of North and South Poles. were implemented from 1979 to 1983.

In 1984, a third pole was established - the Northeast Pole - to exploit a new group of oil fields.

After this, the new discoveries occurred more and more in deeper water fields (above 300m), namely the giant fields Albacora, Barracuda and Marlim.

The philosophy established regarding these deep water giant fields was to consider each one as a pole, gathering the oil production of each into one or more FPSO (or FSO) and flowing out to shore through shuttle tankers. The gas production is flowed out through pipelines.

This paper focuses three different phases of the Campos Basin development, as follows:North and South Poles (1977 to 1983);Northeast Pole (1984 to 1988);Deep water fields (after 1985)

This is a macro division comprising specific phases in which various projects were simultaneously implemented utilizing different concepts, owing to technology evolution as well as to site condition restraints. It is to be mentioned that other developments have occurred during this period and are merely listed herein.
Code Conflicts for High Pressure Flowlines and Steel Catenary Risers
Authors: Langner Carl G. , Shah Bharat C.
Published: October 2008

There is a growing concern among pipeline engineers in the offshore industry that the existing pipeline codes lead to overly conservative designs for the class of high pressure flowlines that transport unprocessed well fluids from subsea wells or subsea manifolds to the first downstream processing facility, usually located on a nearby platform. Of greatest interest are flowlines and steel catenary risers whose designs are dominated by the well shut in pressure, a loading which acts on a flowline only in rare events such as when several subsea valves fail simultaneously. Significant savings in materials, welding, and installation costs can be achieved, together with adequate safety, by changing to a limit state design based on the actual burst strength of pipe. Upgrades to both lay vessels and production platforms to handle the weight of thick walled flowlines and risers can be minized with this design approach.

This paper presents rationale for future code changes and describes attempts under way to make these changes. Appeal is made to the offshore industry to create a large data base of pipe burst tests. These data data be shared by various code committees to develop less conservative design formulas for subsea flowlines and risers. The ultimate aim is to provide a cost effective and reliable design providing a uniform factor of safety independent of pipe size, wall thickness, and grade.

Introduction

Design rules in the existing ASME and API pipeline codes and their counterparts in the U. S. federal regulations generally result in overly conservative designs for high pressure subsea flowlines and steel catenary risers that are connected between subsea production wells and their host platforms, as illustrated in Figure 1. The platform may be a fixed platform, a compliant tower, a tension leg platform, a floating production system, or a SPAR, etc., and the subsea facility may be a single satellite well or a subsea multi-well manifold The typical design outcome is a thick-wall pipe with low D/t ratio, having a burst safety factor between 2 and 4, will be demonstrated by the examples presented below. This compares with burst safety factors of most existing pipelines that fall between about 1.5 and 2.5. Consequently, unnecessarily large steel and welding cost penalties must be paid for flowlines to a deepwater field development project, and major upgrades to layvessels and platform structures may be required to handle the increased weight of the thick-wall flowlines. This is particularly critical for floating platforms where added buoyancy is very expensive.

The main f8ctor leading to this conservatism is the Barlow formula, which was introduced into pipeline design practice in the 1 930's and which loosely relates the maximum hoop stress with the initial yield stress.
Ejectors for Boosting Low Pressure Oil Wells : First Field Application
Authors: Ghetto G. , Paone F.G. , Giacchetta G. , Bevilacqua M.
Published: October 2008

The first world-wide (to our knowledge) field installation of a multiphase d c e ejector has been successfully applied in the Villafortuna oilfield (Italy) on 1996. Ejector installed at Villafortuna 4 (VF4) well increased its oil production rate by 30% and demonstrated the viability of the system as a reliable low cost-low size boosting system, with minimum impact on any existing facility, suitable for applications in existing fields or for new development both on-shore and off-shore.

The paper describes the main steps of the R&D project, developed in collaboration with the University of Ancona, aimed at evaluating the suitability of ejectors as simple and low cost-low size boosting system for oil wells. In addition, the reliability of a computer code, developed by Agip and University of Ancona for the design of the ejector, is discussed.

The paper also presents the activity of tuning for the software, based on a test campaign in which different geometries of ejectors were extensively tested, before with air and water at low pressures, in the laboratory of University (over 400 data points), and after with crude oil and gas in the Agip's multiphase loop of Trecate (over 200 data points).the tests have been executed varying pressure, liquid flowrate, gas-void fraction and outlet common pressure, both for the high pressure stream and for the low pressure stream, covering a wide range of process conditions.

Following the good results obtained from the tests, the installation of a multiphase ejector at Villafortuna 4 well has been realized; The paper describes such installation as well as other studies under development.

INTRODUCTION

The ejector is a static machine in which a High Pressure Stream (HPS) is mixed with a Low Pressure Stream (LPS) in a properly designed mixing chamber. The mixture passes through a diffuser, leaving the ejector at an intermediate common outlet pressure (Fig. 1).

The ejector is a well known equipment extensively used in many industries such as chemical industry (gas-gas ejectors) and nuclear (liquid-liquid jet pumps).

The oil industry limited the use of jet pumps at the bottom hole as artificial lift system, using water or diesel as a power fluid pumped from the surface. For the bottom hole jet pumps the approach used is to treat the gas phase in the low pressure stream (suction stream) as a "liquid phase". This is usually correct for down hole jet pumps, where the gas carried under the liquid stream is frequently limited to small percent (5-10). This assumption is not valid for surface oil ejectors because the gas largely exceed this limit.
Ageing and Fatigue Life of Structural TLP Flexelements
Authors: Gunderson R.H. , Stevenson Andrew
Published: October 2008

This paper presents a methodology for estimating the fatigue life of elastomerlsteel flexelements that includes the effects of both mechanical fatigue loads and ageing of the elastomer. Previous methods calculated the rate of fatigue crack growth in the elastomer layers of flexelements using fracture mechanic analysis and a material fatigue model obtained from tests on new elastomer materials which ignored ageing. This workshows how elastomer ageing can be taken into account and the impact this can have on the calculated fatigue life.

This methodology has been applied to the Design verification of the structural flexelements for the RamPowell TLP tendons to be installed in the Gulf of Mexico in 1997. The tendon flexelements carry the full tendon loads and provide near moment-free joints at the top and bottom of each tendon. The analysis can also be used for riser system flexelements and other elastomer steel layered structural components.

The physical properties of elastomers change with age. The fatigue life of the Ram/Powell flexelement was Calculated to be 5160 years based on the properties of new Elastomer. When the properties of the ageing elastomer were taken into account, the calculated fatigue life ranges from 160 years to 400 years depending on the conservatism of the assumptions used. The effect of ageing is obviously significant. The analysis uses data generated from elastomer samples exposed to accelerated ageing conditions. A special purpose fracture mechanics program calculates the crack growth in each layer for each load in the yearly fatigue spectrum. The material properties are updated and total crack length is computed on a year-by-year basis until the failure criteria is reached.

The present approach may remove some of the uncertainty associated with structural elastomer design, result in more realistic estimates of elastomer fatigue life, and may lead to the use of safety factors commonly associated with the design of more familiar structures.

Introduction

Flexelements are primary load bearing components of the tether system of tension leg and so it is of the Ram Powell TLP it was desired that a large safety factor be demonstrated. Previous work had developed and verified a fatigue analysis method for flexelements. This, however, ignored the effect of ageing of the elastomer with time, whereby the elastic shear modulus may increase and the fatigue resistance may decrease. Previous work had been based entirely on data from new elastomer material and did not include an ageing model in the fatigue calculations.
Limit State Design of Subsea Flowlines for Pressure Containment
Authors: Mahendran Indu K. , Al-Sharif A.M. , Young Charles D. , Langner Carl  C.
Published: October 2008

The current API and ASME design codes on wall thickness selection are too restrictive for the application of high pressure subsea flowlines. At present the codes require flowlines to be designed to wellhead shut-in pressure using Barlow design formula, which is based on first yield, and working stress safety factors established decades ago. Recent advances made in pipe manufacturing, design engineering, and the considerable plasticity of thick walled steel pipe render the current design overly conservative, resulting in severe cost penalties for long distance subsea tiebacks.

The current work describes the application of Burst Limit State Design principles to the design of subsea tiebacks. The paper discusses the limitations of the classical approach and quantifies the uncertainties, risks, and economics of limit state design, based on results obtained from burst pressure test data obtained from various industry sources. It is expected that this work will lead to a review of the existing codes by the regulatory bodies and the recommendation to change current in design practices.

The work will enable deepwater subsea tiebacks to be designed in accordance with limit state principles and safety factors reflecting the current state-of-the-art technology of pipe materials, manufacture, welding, quality control and pipeline design. This will lead to the optimum design of subsea flowlines.

This work is mainly directed towards the large D/T ratios required for high pressure subsea flowlines, and is different from the low D/T ratio work carried out by SUPERB and IS0 working committees in Europe. However, it is intended that this work will complement the work carried out elsewhere, leading to a consistent application of burst pressure design to pipelines and flowlines.

Introduction

DeepStar 3300 Committee commissioned a study to evaluate the feasibility of using the Burst Limit State criteria to design subsea flowlines. The work consisted of:Collection of data from published sources and DeepStar members.Identification of Limit State Design models for Burst Assessment of code compliancePreparation of submissions to API and ASME for code changes

The work presented here is limited to the Phase 1 of the study, and includes a description of the data collected, and the preliminary Limit State Design philosophy under development. Comparative cost data for current design practices, and Limit State Design also given to establish the potential cost savings of using Limit State Design.

Recognition of the uncertainties associated with engineering systems has led to the wide application of the concept of reliability as a basis for structural design. This is evidenced by the move in Europe and North America to develop limit states codes for pipeline design.
Underbalance Perforation in Long Horizontal Wells in the Andrew Field
Authors: Kusaka K. , Patel D. , Gomersall S. , Mason J. , Dought P.
Published: October 2008

The comparison of today's slickline capabilities with its early usage for routine remedial workovers and maintenance best illustrates the significant advances that have occurred within slickline technology. Today, for example, slickline can be used to I) set and retrieve slickline-retrievable safety valves or plugs, 2) open and close downhole circulating devices, 3)retrieve accurate depthhime data for correlating with memory production surveys for well diagnostics (problem identification) reservoir description, or flow analysis, 4) provide accurate correlation of tubing casing collars, and 5) pull and run multiple flow controls set packers and other downhole equipment without explosives; setting monobore tools; and other perform other well interventions that are dependent upon measurement accuracy. Less than a decade ago, slickline was only considered for mechanical well workovers.

This paper will discuss the newly developed technology that allows slickline to economically provide alternatives to services traditionally reserved for other, more costly options. Case histories will be used to illustrate the enlarged scope of services and how the equipment combines to provide the innovative low cost service options that the industry has been seeking.

Introduction

Economic initiatives are usually the drivers of new technologies, and thus, reacting to the significant decline in the oilfield climate during the last decade, no era has been as momentous in providing stimuli for operational change. Unfortunately, operators who are seeking new methods usually look to new technologies as the potential problem solvers, and in so doing, overlook enhancements to the older, proven technologies that could provide the cost efficient alternatives they want.

This has been the case with slickline. Until the resurgence of investigation into new strategies to meet the oilfield cost constraints of the last decade, slickline service was only considered for routine mechanical workovers. Who would have considered using slickline to set a packer in the early 90's.

The capabilities that have changed the profile of slickline service from one of routine mechanical well work overs to a multi-faceted service technology are derived from the new slickline tools that can be used independently or combined to further enhance the scope of services. The equipment includes an electronic triggering device (ETD) that enables safe detonation of explosive devices, a battery-operated, electro-mechanical tool that sets wellbore devices on slickline and braided line without explosives, an electronic measurement system that automatically corrects measurement inaccuracies resulting from line stretch and environmental stress factors, a slickline collar locator (SLCL) that accurately verifies collar locations in a tubing string, and data job loggers or acquisition software systems that connect to the electronic measurement system to graphically record dynamic wireline information.
Development & Application of a Through Tubing Multi-Lateral Re-Entry System.
Authors: Brooks Robert T. , Stratton J. Jay
Published: October 2008

The drilling of multi-lateral wells is an established process, but the selective entry, and reentry of single, or multiple, lateral wellbores is an engineering problem that is still being addressed. The economic rewards from multi-lateral wells have not been reliably understood due to the unpredictable nature of overall costs versus performance. Poor capabilities for reservoir surveillance contribute to the difficulties in evaluating production performance and drainage efficiency from individual zones. Performance evaluation can be M e r complicated by effects of cross flow from adjacent heterogeneous zones.

This paper presents a completion system that allows recovery of considerable reserves from the 'A' and 'B' zones of the Shuaiba reservoir in the Idd El Shargi North Dome Field, while providing cost effective reservoir surveillance of zones drilled with horizontal multi-lateral well technology.

Introduction

The Idd El Shargi North Dome Field (ISND) is situated in the Arabian Gulf, 90 kilometers east of Doha, Qatar (Fig 1). The discovery well for ISND, IS-2, was drilled in 1960. Production began in 1964.

Initial production from the field was from Jurassic Araej and Uwainat Formations. Production was later achieved from the Jurassic Arab Formation and Cretaceous Shuaiba Formation. The majority of production is from the Arab 'C', Arab 'D', and Shuaiba Formations. About 2.0 billion bbls of the ISND Fields 4.2 billion bbls OOIP are in the Shuaiba Formation. Still, the reservoir is relatively undeveloped. The Shuaiba is a carbonate formation with reservoir top at about 4500 feet subsea and capped by the Nahr Umr Shale. A 600 ft oil column is divided into 4 geologic zones, the Shuaiba 'A', 'B', 'C', and 'D'. The Shuaiba 'A' and 'B' intervals, with average porosity of 24% and permeability of 5 md, hold 82 percent of the Shuaiba OOIP. The intervals are separated by a tight layer in many areas of the field. With an existing infrastructure already in place, the low permeability Shuaiba 'A' and 'B' intervals are prime candidates for horizontal multi-lateral development that can optimize use of remaining well slots and production facilities.

Well IS-76 was selected as the first horizontal multilateral completion candidate. The main borehole was drilled to a horizontal orientation in the Shuaiba 'B' interval, and 9- 518" casing cemented in place. The casing string included an oriented predrilled casing exit window. This was run in the casing string at the depth where the lateral borehole was to be drilled into the Shuaiba 'A' interval. The orientation of the pradrilled casing exit window was to the high side of the casing (to prevent any debris entering the lateral bore at a later date). After cementing the casing in place, and subsequent clean out work, a drilling whipstock was run in the well.
Multiphase Flow Meters and Application Trends
Authors: Hatton Gregory J.
Published: October 2008

Multiphase flow meters are being utilized to provide well test data in a growing number of oil production applications. These include subsea applications that eliminate the need for costly well test lines, topside applications that minimize platform space and load requirements for well testing, and applications in remote or unmanned locations. This paper reviews key technologies used in the commercial meters being deployed in the field in significant numbers, and trends in multiphase flow meter applications.

Introduction

Multiphase meters are systems that meter multiphase flow streams in situ i.e., they meter the individual component flow rates without first separating the components. As well test systems, multiphase meters measure the gas, oil, and water flow rates of a well stream without large conventional three-phase separators.

Multiphase flow meters differ from conventional well test systems in several ways. Generally, multiphase flow meters (1) measure well production rates quicker and with less human intervention, (2) are smaller and less massive, (3) provide additional valuable data, and (4) are deployed subsea.

Traditionally, operators have monitored individual-well flow rates to maximize field and reservoir performance with conventional three-phase separator, well test systems. In these surface well test systems, ideally, a three-phase separator provides pure oil, pure water, and pure gas streams to single phase meters. In subsea applications, (in addition to a production line) a test line is laid from a subsea manifold to a conventional well test system on a platform to allow testing of individual wells. As the platform-to-subsea-manifold offset increases, the difficulties associated with acquiring accurate well tests (for a range of flow rates) increase, and for large offsets. a conventional test-line system becomes ineffective. The capital costs and the operating costs (including man power) of traditional systems have lead to the development of multiphase flow meters. These meters are intended to reduce costs and manpower requirements, and to provide timely well testing at remote locations.

The effective application of multiphase flow meters requires an understanding of their working principles and how these affect:Qualification of a meter for a particular application. Installation considerations.Calibration during the field lifetime.Accuracy of the measurements under various conditions.Stability and repeatability of the measurements.Measurement robustness. (That is, how resistant is the meter to being fooled and reporting erroneous rates?)Meter state-of-health evaluation.

In order to obtain desired metering performance, each application should be carefully engineered with regard to meter selection, installation, calibration, and data handling and interpretation.

Multiphase flow meter manufacturers provide a range of viable well test systems for subsea, topside offshore, and onshore applications. These meters use relatively high levels of electronics and are designed for unmanned operations.
Alwyn Area: A Case History in Improved Business Performance
Authors: Dundas I. , Grosjean Y. , Hervochon J.
Published: October 2008

The Alwyn North field, situated in the UK sector of the Northern North Sea, came on stream in late 1987. Development used classic North Sea technology. Plateau production was originally forecast to last no more than four years for oil, and seven years for gas.

Over the past three years Alwyn North has been developed into an integrated area operation with the start-up of the adjacent minimum-facilities Dunbar field and the sub-sea development of the Ellon field. The Dunbar field has made full use of new technology, including Tender Assisted Drilling, a lightweight jacket and multiphase export. Substitution terms incorporated within the gas sales contract allowed movement into new emerging UK gas markets.

Increased reserves have been identified by the application of 3D-seismic and the further appraisal of new (and old) reservoir compartments. Increased productivity has been achieved through debottlenecking of the process plant and by drilling long reach horizontal wells. Increased cost effectiveness has been delivered by a "continuous improvement" campaign resulting in OpEx reductions and increases in oil and gas sales.

A further phase of developments is now in preparation. On Alwyn North an infill drilling campaign is scheduled to follow the interpretation of the newly acquired second 3D survey, and a miscible gas injection scheme is currently being studied. On Dunbar the installation of multiphase pumps will sustain export potential and further sub-sea developments will be phased in. An autonomous power supply and acoustic communication scheme is under review to improve economics of long distance tie-backs.

Initial Development of Alwyn North

The Alwyn North field, developed jointly by Total Oil Marine plc (33.3% - operator) and Elf Exploration UK PLC (66.7%) was originally discovered in 1975. Development consent was given in 1982 on the basis of initial recoverable reserves of 385 Mboe (200 Mbbls of oil and 26.6 Gm' of gas) with a production plateau of four years for oil, seven years for gas, followed by a progressive decline through to 1998. A series of discoveries had been made in an area to the south of Alwyn North, but they were considered uneconomic to develop at that time.

The field is situated in the northern sector of the North Sea, 140 kms to the east of the Shetland Islands and 465 kms north-east of Aberdeen, in close proximity to the Brent and Ninian fields (Fig 1).

There are two main reservoirs. The Brent oil reservoir at 3,100 metres is hghly compartmentalised into panels, each supported by water injection. A total of ten oil wells and seven water injectors were drilled. The Statfjord gas reservoir, slightly deeper at 3,400 metres, was developed by twelve wells using natural depletion (Fig 2).
Contribution Of Flexible Pipes And Riser Systems To The Development Of Subsea Hydrocarbon Resources
Authors: Narzul P. , Dumay J.M. , Rigaud J.
Published: October 2008

The paper reviews the parallel developments of the flexible pipe technology and of the subsea industry. It analyses the key characteristics which have made this development possible and which are, basically, flexibility, modularity and versatility. This has allowed the flexible pipe not only to stick to the market, but even to make it possible, as it is an element without which floating production systems would hardly exist. As a result, flexible pipes are now natural components of most subsea developments.

Introduction

The contribution of flexible pipes to subsea developments was recognized in 1995 in this very forum, under the form of an award for "distinguished contribution to the development of subsea oil and gas technology", which, in itself, justifies the title of this paper. However, when the flexible pipe was first conceived, this was not a foregone conclusion.

The history of technology is full of inventions which turned out to be successful in ways their inventor had not always foreseen. Flexible pipe technology is a good example of this. The award came more than 25 years after the concept was developed by the French Petroleum Institute (IFP), and it is ironic to reflect that, initially, the product was not aimed at the subsea industry which, anyway, was still in its infancy at the beginning of the seventies but at drilling technology. This pplication was not a success, so that in 1972 the flexible pipe was really a product without a market.

The purpose of this paper is, beyond briefly recalling the history of the technology, to explain why flexible pipes answered the challenges of subsea developments and how the adequation of the product to the market was maintained as the range of applications was extended. The most interesting question for the future is whether this fit between a product and a market will persist as the subsea industry evolves. This will be discussed in the last section.

Historical milestones

The first flexible pipes where built in the early seventies to replace the steel stems traditionally used for drilling. The ambitious objective was to eliminate the time-consuming manipulation of drilling stems which is required whenever the drilling head has to be changed. The idea was interesting, and the first trials were relatively successful, but the torsional properties of flexible pipe were too low and the pipes were quickly and easily damaged. There was no hope that this technique could replace the current, field-proven methods and the idea was abandoned. In the meantime, Elf needed a short flowline in West Africa, on the Emeraude field, in order to transfer crude oil between two platforms. This is when the application of flexible pipes to the offshore oil industry was first considered and implemented, in 1973. However, this market remained somehow anecdotal and the number of applications limited.
Computing and Visualization Point the Way Ahead for Reservoir Characterization
Authors: Neidel Norman S.
Published: October 2008

Progress in modem digital computing and related display technology have propelled seismic technology and the use of geological information into an era where imagination has no bounds. Displays we now can view almost routinely are particularly impressive. At the same time such "enabling" processes point out the weaknesses in the state-of-the-art as well as noting the strengths where we use seismic and geologc data to find and define hydrocarbon reservoirs.

Where single type data sets are treated individually, well logs, seismic data, engineering measurements, etc., the &splays we can create and the insights which we can develop are quite remarkable. The new tools which we employ, diprates, coherence values and such are just the fore-front of the avalanche of progress which will inevitably follow.

Where we fall short is when we must integrate or synthesize differing data types. The principal failing here is in establishing analytic formalisms connecting the various types of data. Without these mechanisms reliance is placed on geostatistics, but at a stage which in many instances is premature. It is likely that the inconsistent and limited success of such methods rests with this circumstance and underlying deficiency.

The likely avenues for future developments should follow from these two themes. We should see further progress of course where there has already been success - more and better analyses will delve still further into the significance of the data we have. At the same time, the urgent need to crossrelate data using underlying physics-based models will motivate new approaches. These should improve both effectiveness and the scope of applications where data synthesis is involved. Under such circumstances geostatisticsshould take on a more appropriate and reliable role.

AS these developments further mature, we shall move from marveling at the form of the displays we may conceive. to an appreciation of their substance. The examples and studies 4; sw now indicate that the projections offered here are not overstated, but are in fact quite reasonable.

Introduction

Recent advances in seismic technology while spectacular in was presented accomplishment have been tied only rather loosely or indirectly to the underlying geology. As one example. 3D surveys have primarily progressed imaging of structures, but have had more limited success with stratigraphic objectives. Such applications are however, starting to emerge as for example use of the Amoco Coherence methods in delineating channels on time slice presentations. At the same time, improvements in geologic understanding and newer tools such as basin models remain poorly coupled to seismic technology. Seismic stratigraphy remains at present a qualitative method - almost an art.
Design and Qualification of Advanced Composites for Marine Applications
Authors: Newhouse Norman L. , Johnson Douglas  B. , Baldwin Donald  D.
Published: October 2008

Lincoln Composites has designed and qualified all-composite pressure vessels for use in commercial applications. This paper presents history, analysis, and test results for composite pressure vessels.

Lincoln Composites has extensive experience in the design of composite pressure vessels for the aerospace defense industry. This experience has been extended to the development of pressure vessels for commercial service that use a hybrid carbon/glass fiber reinforcement with a plastic liner. The first application of these pressure vessels was for use as high pressure fuel containers for Natural Gas Vehicles, with qualification in accordance with ANSIIAGA NGV2. There are currently over 10,000 of these pressure vessels in service.

This technology has been further extended and applied to use in tensioning systems for offshore oil platforms, with qualification in accordance with Section X of the ASME Boiler Code. Three configurations have been designed to date. A total of 124 pressure vessels have been fabricated for use on the Mars platform. These pressure vessels have a maximum operating pressure of 3,000 psi, and are 17.3 inches in diameter and 82.5 inches in length. Sixteen pressure vessels have been fabricated for use on the Ram Powell platform. These pressure vessels are 20.1 inches in diameter and 8 1.7 inches in length. Pressure vessels now in design and test for the Ursa platform are 20.1 inches in diameter and 104 inches in length.

Results of design studies are presented, as are development and qualification testing for the NGV2 and ASME pressure vessels. This includes results of burst, cyclic fatigue, environmental, and damage tolerance testing. These pressure vessels have excellent fatigue performance and are corrosion resistant, light weight, and durable. This combination of properties, in addition to reduced costs compared with traditional steel pressure vessels, offers significant benefits for use of all-composite pressure vessels on off-shore platforms.

Background

Lincoln Composites was founded in 1963 to manufacture the Polaris third stage rocket motor case as part of the Technical Products Group of Brunswick Corporation. Lincoln Composites became part of Technical Products Group, Inc. in May 1995.

Composite materials are used in rocket motor case applications such as the Peacekeeper (MX) second stage, Minuteman third stage, large and small ORBUS (IUS), Trident D-5 third stage, and PAC-3. Composite motor cases typically use glass, aramid, or carbon fiber reinforcement, and have a rubber liner which serves as a gas permeation barrier and as thermal insulation.

Pressure vessel technology was a natural outgrowth of the rocket motor case technology. Development details are discussed below.

Composite fuel tanks are a further extension of motor case and pressure vessel technology. Applications include 480-gallon and 330-gallon external fuel tanks for the F- 18 aircraft and 230-gallon fuel tanks for the Apache and Blackhawk helicopters.
Petroleum Developments in Western Australia
Authors: Fraser I. , Bruce R.H.
Published: October 2008

From relatively humble beginnings to its world class billion dollar projects, Western Australia has become the focal point of Australian oil and gas production. Currently it is the nation's largest producer of hydrocarbons and ranks fourth in world LNG production. The rapidly expanding oil and gasindustryl is the State's fastest-growing economic sector with output totalling about US$3.4 billion per annum. This paper is one of three which review opportunities and growth in the petroleum industry in Western Australia.

In the 1970's exploration drilling on the North West Shelf yielded the giant Scott Reef, North Rankin, Goodwyn, Angel and Scarborough gas-condensate fields. The giant Gorgon gas discovery was made in 1981. The perception of the NorthWest Shelf being gas-prone changed in the 1980's with major oil discoveries at Wanaea, Cossack and Griffin. Since then numerous oil discoveries have been made in other areas of offshore Western Australia including Wandoo, Stag, Laminaria, Buffalo and Cornea (Fig. 1 and 2).

Infrastructure continues to grow with further field developments on the North West Shelf. The presence of facilities and pipelines will facilitate production from existing oil and gas ields, and the development of other fields and discoveries. Production facilities used now include conventional platforms, mini platforms, concrete gravity structures, automated buoys, monopods, subsea completions and tiebacks to FPSO's. In 1997, 28 North West Shelf oil and gas fields produced some 64 million barrels of oil, 40 million barrels of condensate and 803 BCF gas, A synopsis follows.

Oil and Gas Developments

Barrow Island (WAPET).

The onshore Barrow Island oil field was discovered in 1964 and is the largest oil field discovered to date in Western Australia - over 1 billion barrels in place2 Production commenced in 1967 and peak production of 50,000 barrels per day was reached in 1971. In excess of 800 wells have been drilled on the island, including 440 oil production wells, 240 water injection wells, and various gas producer and water disposal wells. Infill development drillingphases are underway. The majority of producing wells use beam pumps to pump oil to the surface. The remaining producersuse gas-lift or are on natural flow. Produced fluids are piped from each well to one of ten separator stations. Clean oilis pumped to the main oil storage facility, comprising five 200,000 barrel tanks. The oil is then piped through a 6 mile long submarine pipeline to an offshore mooring system where tankers are berthed. WAPET comprises Chevron, Texaco, Mobil and Shell.

Offshore Airlie Island (Novus).

The South Pepper oil field was discovered in 1982, North Herald and Chervil in 1983. In order to improve oil recovery from thin oil sands and decreaseproject costs, alternative development approaches were considered3. Rather than constructing a high capital cost productionplatform, the Vicksburg jackup rig was modified with the addition of on board production processing equipment andused over the South Pepper field.
Dissection and Culture of Embryonic Spinal Commissural Neurons
Authors: Moore Simon W. , Kennedy Timothy E.
Published: October 2008

Studies of spinal commissural neurons have provided substantial insight into the mechanisms that regulate axon guidance. Explants of embryonic spinal cords and isolated spinal commissural neurons have been important experimental tools for the identification and characterization of several guidance cues, including netrins, semaphorins, slits, sonic hedgehog, BMPs, and wnts. In this unit, protocols are provided for establishing these explant assays to assess the outgrowth and turning capacity of commissural axons. In addition, methods are included for preparing cultures highly enriched with embryonic commissural neurons, which have been used to probe the biochemical signaling mechanisms regulating axon guidance. Curr. Protoc. Neurosci. 45:3.20.1‐3.20.17. © 2008 by John Wiley & Sons, Inc.