bluuebunny/crossref_metadata_2025_split huggingface dataset:
Quantifying Seismic Amplitude Distortions Below Salt
Authors: Muerdter D.A. , Lindsay A.O. , Ratcliff D.W. 
Published: October 2008

Abstract
Interpretation, drilling, and discovery of subsalt reservoirs has been enabled by development of 3-D prestack depth migration of large marine 3-D seismic surveys. Although this technology has greatly improved imaging below salt, questions remain about amplitude variations in the data. This investigation uses raytrace modeling to study the aerial variations in the amplitudes of the subsalt reflections causedby complex salt structures and by large overlying velocity variations. The ultimate goal of this research is to understand the distortions and subtract them from the data, so that themore subtle variations in the seismic response caused by gas, oil. or brine in the reservoir rocks may be ascertained.
A 3-D computer model was built from the seismic and velocity volumes prodUced by 3-D prestack migration. Northsouth and east-west oriented 3-D seismic surveys were simulated in the model using Landmark's QUIKSHOTprogram. The raytracing results were sorted into reflection point gathers similar to the migration process used in 3-D prestack depth migration. Maps of the rays that hit a reflection-point bin and of the total and average amplitude per bin were prepared and analyzed. The following results were produced:Below the salt, hits per bin vary from 0 to 200 for data shot with geometric 30-fold coverage.The tota1 amplitude per bin varies by more than an order of magnitude.The edges of the salt bodies cause extensive distortion because of the salt's steep slopes and the bending of the rays that pass through the salt compared to those that do not.The salt shapes are so complex that generalizations are difficult and 3-D seismic modeling is needed to understand subsalt coverage.There are large differences in subsalt coverage between surveys shot in different directions. A multi-directional 3-D shoot would add significantly to the true reflection-point fold in most areas under sall

Introduction
As of December 1996, at least 7 subsalt discoveries have been reported in the Gulf of Mexico (Moore and Brooks, 1997) 1. A significant contribution to these successes was the availability of prestack depth migration (PDM) of 3-D seismicsurveys. In many areas the advent of 3-D PDM enabled imaging of the subsalt structures for the rust time (Ratcliff and Weber. 1997)2.
But areas still exist that are difficult to interprel Figure 1 shows a north-south line from the 3-D prestack depth migrated line over the Mahogany No. 1 discovery well. Near the well horizons are mappable. But to the north the subsalt data is difficult to interpret. Under the edges of the salt thedata become noisy and it is difficult to follow a reflector through this area. This study uses raytrace modeling to explain the seismic response observed below salt and to identify improvements in data acquisition. Another reason touse raytracing is that most 3-D prestack depth migrations currently use raytracing to move the energy recorded to its proper spatial position.
International Alliances: Closing the Cultural Gap
Authors: Farrell Susan , Watzke Jerry 
Published: October 2008

Abstract
As alliances become increasingly common around the world, differences in cultural expectations and the use of language have taken on a new and critical importance. This study examines the importance of cultural issues in the successful implementation of projects where participating companies are linked in a risk/reward agreement.
The review of alliances, including British, American, Canadian, Australian, Arab and Asian companies, revealed that strongly ingrained national cultural characteristics such as acceptance of authority and position in a hierarchy, style of communication, and perceptions of risk stongly influenced the ways in which a team functioned. In addition, however, there were very clear industry and company cultures which were overlaid on the national traits. The interplay of the three detennined the willingness or not of different members to adhere to such basic alliance principles as openness, egalitarianism and empowennent.
In no case did we find that the alliance members were given any cultural training nor were they particularly familiar with their partners' national, industry or company cultures. Often it was only after the project was underway, and the joint targets had already been set, that the members clearly understood thatdifferent interpretations existed of the so-called agreement.
Although the energy industry has long dealt with multiple nationalities, the introduction of alliance structures has greatly enhanced the need to understand and to incorporate differentcultures into the functioning of the team. Clear communication becomes a key element in the setting of alliance nonns and goals and the recognition that English will be interpreted in different ays is important in maximizing alliance results.

Introduction
Alliances are becoming increasingly commoll' in the international energy industry as operators search for ways in which to improvethe economics of projects. Even originally skeptical managers have come to believe that the dynamic created in an open environment, with different companies sharing ideas, creates more savings than would have occurred using traditional, segregated ways of working.
Alliances have now spread outside of the US and UK to embrace projects in the Middle East and Asia. As the use of this contracting structure grows, it will inevitably encounter successes and failures, attracting admirers and protagonists. But alliancing is here to stay. An understanding of the critical elements affecting the interactions among members will prove invaluable in constructing a set of partners with the greatest chance of success.
A previous study was conducted by the authors to identify key elements necessary for alliance success and published as OTC 8091, "Lessons Learned on International Partnering and Alliance Contracts"(l). Although not addressed in that paper, the research revealed the importance of cultural issues as an influence on alliance outcomes. The alliances surveyed here differ from those in OTC 8091 and were specifically chosen for their multi-national content.
lntroduction to the Troll Project
Authors: Wheeler Peter J. 
Published: October 2008

Abstract
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

Abstract
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

Abstract
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

Abstract
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

ABSTRACT
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.