bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Growing Importance of 3-D Seismic Technology
Authors: Schoenberger M. 
Published: October 2008

Introduction
3-D seismic technology is arguably the most important E&P technology to have developed during the past few decades. The significance of this technology is illustrated by the exponential growth in its application. Figure 1 illustrated the growth in Exxon's use of this technology-as measured both by the area coved and by money spent on it. What has accounted for this tremendous growth? Will it continue?
This artielc is arranged logically to illustrated how 3-D seismic technology has develop its current status and how it needs to change in order to he even more valuable in the future than it is today.

The Early Days
Note in Figure 1 that 3-D seismic exploration began in the middle 1970s. However, the Wzhnologyused in those early surveys had been developed during the previous duple. 3) Hktundly, Fitly groups contributed to the success of 3-D Seismic exploration. However, in my view, three seminal activities Most of the Credit.
1) During the 1960s Exxon developed the expanding wave front 3-D seismic impark tecludque. In its most common implementation, a lid of geophones was placed orthogonal to a line of shot holes. Each shot detected by the geophones illuminated a line in the subsurface when all shots had been recorded a rectangular subsurface region had been illuminated.
The shot record were placed on movie, film Exxon-developed fiber-optic viewer extracted and displayed all of the data recoded at a give arrived time; i.e., its output was a succession of rime slices through the seismic wave field. Figure 2 shows a succession of wave fronts reflected from a horizontal layer. At 1680ms the dot in the center is the reflection arriving at the nearest offsets. At 1800 ms the wave front reached the farthest offsets. If the reflector had been dipping, the wave front would have been non-concentric. If the reflector had been vertically each wavefront would have comprised two semicircles with different radii. The Exxon work was presented at the 1970 SEG Convention and appeared as a 1972 GEOPHYSICS paper'.
2. In the early 1970s GSI (at that time, a prominent geophysicalservice company) developed Seiscrop, a method for displaying areal views of seismic data volumes. Inspired by Exxon's presentation, GSI developed a time-slice approach that instead of slicing through seismic Instead of through processed 2-D seismic sections. Instead of wavefronts they displayed areal views of the reflections. In the 1970s digital technology was still fairly new, so the GSI researchers used the same display medium as the Exxon researchers time slices recorded on movie film. The display was in analog form on a Seiscrop table-the forerunner of today's interactive workstation.
Using 3D seismic and attribute analysis to track fluid movement in the subsurface
Authors: Luheshi M.N. , Ahsvihare S.G. , Evans J. 
Published: October 2008

Abstract
In 1993, there was a well control incident while drilling a prospect offshore Vietnam. This incidentnecessitated the implementation of an extensive seismic monitoring programme. It became rapidly apparent that conventional high resolution seismic techniques for identifying and monitoring gas in the subsurface were inadequate due to loss of signal power through the system.
This problem drove the need for an innovative approach to acquiring a 'Medium Resolution 3D Suwey'. This had two important characteristics, namely significantly higher bandwidth than conventional 3D data and also having the penetration necessary in order to image the target reservoir, through a disturbed overburden.
This paper describes the technology used in acquiring and processing the data, as this has relevanceto use of this type of acquisition for conventional reservoir description purposes. It also describes the attribute analysis developed to compare multiple vintages of seismic in order to be able to track fluid movement in the subsurface.
The enhanced resolution achieved has relevance to enabling better reservoir characterisation in general. The attribute analysis is an example of how these type of data can then be conditioned in order to allow tracking of fluid in the subsurface, in appropriate situations.

Introduction/background
Using seismic data to track fluid movement is a fairly well known technique, but one that still needs considerable development for routine use. In certain situations the rock properties of an interval change significantly enough to create a measurably different seismic response. [n order to apply this technology it is necessary to establish an understanding ofThe distribution of rock properties in the interval of interestThe scale of the change in seismic response caused by different fluid fills (water, oil, gas)Whether the quality of the available seismic data has the amplitude, time and depth resolutions required to detect these changesAnd, for monitoring cases, whether the quality of the seismic is controlled sufficiently to enable comparisons between successive surveys
In the case presented here, the interest was in monitoring possible subsurface gas movements following a well control incident. The technical problems and the approach, however, are quite generic; in that the same principles apply for fluid monitoring experiments in conventional production situations.
For the particular problem presented here, it was necessary to establish the history of gas movement in the subsurface using a series of seismic data sets which had different acquisition and processing histories. The need was to understand to what extent it was possible to measure the extent of gas charged sands using these seismic data sets.
The Use of Exploration 3D Data in Geohazard Assessment: Where does the Future Lie?
Authors: Hill A.W. 
Published: October 2008

Abstract
Increasing use is being made of exploration 3D datssets in geohazards evaluations. This new attitude towards the use of exploration data has occurred whilst operators have been revising all their oilfield working practices. The streamlined approaches to exploration through to development have required site investigation practices to be refined to allow business plans to maintain the speed and momentum of their projects whilst ensuring safety. Using explorers's 3D data to screen potential well or platform locations or even pipeline routes the Site Investigation Specialist can ensure that inappropriate locations or routes are not surveyed whilst minimizing survey costs.

Introduction
3D seismic data is not a new phenomenon. The 3D seismic approach has been available to the explorationist for over 20 years. Originally its cost and the length of time it took to process the data meant that the approach was perceived to be of use only to field development and not the exploration phase of prospect evaluation. However, over the last four years there has been a revolution in the turnaround time of 3D data from completion of acquisition to arrival of data for interpretation on the workstation. Whereas turnarounds were previously ofien greater than one year before arrival of first pass processed results, delivery is now regularly within four months of thefinal shot being fired. At the same time the reduction of unit acquisition costs have made the use of 3D data more attractive for use in initial exploration prospect identification. The latter aspect has been largely brought about by the breakthroughs in acquisition approach. Surveys are now being regularly acquired with eight or more streamers allowing ever greater acreage to be covered by 3D surveys faster than ever before and at a lower unit cost.
This is well demonstrated in the west of Shetland arena of the UK continental shelf. Irr the beginning of 1990, althoughthe area had seen exploration activity for at least ten years, not one single 3D survey had been acquired. By the end of 1992 only two small 3D surveys over the Clair Field, totalling only 440 square Kilometres, had been acquired. 1993, however, marked a watershed. [n 1993 the number of streamers being towed on 3D surveys began to increase dramatically, this coincided with the 'faster - cheaper 3D' demands of the operators. It also coincided with a surge of renewed interest in the West of Shetland area. The result is that by the end of 1996 some 15500 square kilometres of 3D data will have been acquired in the area
However, this explosion in 3D data coverage is not special to this area of the UK continental shelf. The story is repeated across the North Sea and especially in the Gulf of Mexico where either proprietary or speculative 3D datasets provide almost blanket coverage.
Techniques and Experiences Using Exploration 3D Seismic Data to Map Drilling Hazards
Authors: Heggland R. , Nygaard E. , Gallagher J.W. 
Published: October 2008

Abstract
This paper will review Statoil's experiences and techniques applied to the mapping of drilling hazards by using exploration 3D seismic data. During the period since first implementing thus approach to shallow gas evaluations, in 1989, the methodology has continued to develop. Attribute mapping techniques have improved the identification of shallow gas and shallow gm traps. Seabed topography may also be mapped using 3D data and attribute analysis. The observation of gas migration through the sediments has significance for the understanding of potential shallow gas accumulations. and different attributes are used to aid in identifying possible gas migration paths. The use of 3D data, modern interpretation techniques and correlation to an extensive well data base, covered by the 3D data, has led to a better understanding of the shallow geology and result in rapid and precise geohazards evaluations. Costs are reduced by minimizing the standard site survey acquisition programmed. and the high degree of accuracy of the predictions has consequences for well planning. leading to safer and less expensive drilling.

Introduction
The technique of using exploration 3D seismic data for detection of shallow gas was pioneered by Statoil during a shallow gas project lasting from 1986 to 1989'. Shallow gas evaluation based on 3D data has since been a standard procedure in Statoil, The technique has, to date, been performed for more than 50 Iocation, i.e. exploration wells, production wells and platform sites, About 150 wells have been used as correlation wells, Early results from Statoil soon encouraged other oil companies to try the same methods, which has had a major impact for site survey contractors who have since had to modify their services offered to accommodate thechanging technology. Later, the Norwegian authorities changed their requirements for shallow gas investigations accordingly to include the use of exploration 3D seismic data where available. The most significant aspect of using 3D data to map drilling hazards is the use of horizontal displays (time slices attribute maps), leading to a better understanding of shallow gas settings and greater reliability of predictions which SUICCimplemented has had an accuracy close to 100 %0. Cost savings by reducing the site survey programmes arc significant. In addition considerable amounts arc saved in the drilling operations due to the accuracy of the predictions which has a direct impact on well planning.

Interpretation Techniques
The method proposed by Gallagher et al,, 1989' and 199 I', was to perform shallow gas evaluations using exploration 3D data loaded to an interpretation station. The most important advantage of this method was the possibility of using time slices. which recvcled shallow gas traps, in particular buried iceberg ploughmarks.
Multi Channel FM Reflection Profiler for Buried Pipeline Surveying
Authors: Schock S.G. , LeBlanc L.R. 
Published: October 2008

Abstract
A towed multi-channel FM acoustic reflection profiler has been developed for locating and generating images of buried objects. One significant application of this sonar is buried pipeline surveying. The multi-channel reflection profiler uses 16 line arrays mounted in a towed vehicle to determined the position and burial depth of an 18 inch steel pipe filled with concrete buried under 1.5 meters of sand. This sonar will allow a survey vessel to continuously track a buried pipeline providing a continuous record of pipe burial depth and position.

Introduction
Locating buried objects under the seafloor is a difficult problem because sediments have surface and volume scattering coefficients that are three orders of magnitude greater than that for water and, consequently, generate acoustic scattering noise that is usually greater than the reflection amplitudes of buried targets. Single channel profilers are practically unusable for finding single objects in sandy seabeds because they have to be towed within a couple of meters of the seabed, can only effectively cover a narrow swath (e.g., less than 2 meters), andprovide little information about object shape and size. Recent experiments using a single channel FM profiler for finding ordnance buried less than a meter in sand show that the beamwidth must be less than 30 degrees and the vehicle tow height must be about a meter above the seafloor in order to reliably detect the ordnance shells.
Buried pipeline surveying is not as difficult as finding buried objects that have a finite length, because towed vehicle positioning is not as critical; the towed sonar vehicle will always pass directly over the pipeline during a crossing. Usually a sonar with a wide along-track beamwidth and a narrow across- track beamwidth is used to find buried pipelines. Survey vessels usually measure the burial depth of pipelines by performing 90 degree crossings of the pipe at selected locations along the pipeline. As the sonar approaches the pipe during each crossing, the two way time travel of the pipeline echo decreases until the sonar is directly over the pipeline. Then the time travel increases as the slant range from the sonar to the pipeline increases. On a paper chart the pipeline echo forms a hyperbola which has a peak at the location where the profiler was directly above the pipeline. Because the crossings must be approximately perpendicular to the pipeline to keep the normal incidence component of the pipeline in the main lobe of the sonar, a pipeline survey can be costly in terms of time and can not provide a continuous record of pipeline burial depth.
Some sediments which have high scattering coefficients due to gas bubbles, shell or other in homogeneities prevent the use of conventional pipeline tracking sonars. In these environments, EM techniques are commonly used to measure pipeline burial depth under the seabed.
Planing and Development of South Pass Block 47 Drilling and Production Platform
Authors: Brokmeyer James E. 
Published: October 2008

Abstract
In February and March of 1993, Energy Development Corporation (EDC) drilled discovery wells in South Pass Blocks 34 and 47 (SP 34 and SP 47). Evaluation of the logs and geologic data indicated reservoirs small in size relative to the water depth and seafloor conditions in the area. EDC'S previous knowledge and experience with the soil condition in the area immediately signaled a very low probability of commercial development of these reservoirs if anything other than a conventional type platform would be required. This paper is a summary of the tasks undertaken to find a way to be able to develop the reserves economically with environmental and safety concerns a high priority.

Introduction
EDC'S initial exploration plans in this area included a geologic prospect in SP 34 and a separate feature in SP 47. It was known through seismic interpretation that the feature in SP 47 would likely be approximately I/3 the size of SP 34 reserves, Therefore, the initial plans called for drilling a discovery well in SP 34 that could be salvaged and utilized as a producing well should SP 47 be proven uneconomic, and an expendable well in SP 47 to test the reservoir. Upon the drilling of the first wells, the final assessment yielded the predicted results of a sizable reservoir in SP 34 and a reservoir approximately 1/3 the size of SP 34 in Block 47.

Planing
Drilling of the wells in SP 34 and 47 resulted in providing the critical information that was necessary to both size the production facilities, but more importantly dictate a maximum amount of capital that could be expended, and yet yield an acceptable rate of return for EDC. At this juncture, several options were available to develop the reserves.

Option 1.
Set a conventional platform at the drill site in SP 34 and abandon the reserves in SP 47 as uneconomic.

Option 2.
Pick a platform site suitable to drill directional wells to develop both Blocks.

Option 3.
Set a conventional platform in SP 34, install a subsea caisson wellhead in SP 47 and lay a flowline to the SP 34 platform.

Option 4.
Install a mud slide design platform at a common site to develop Blocks 34 and 47.

Development
In the case of Option 4, cost estimates in the range of $25,000,000 immediately excluded this as an option. If no other plan could work, the reserves would be uneconomic to develop. It was therefore decided that additional detailed soil data would be required in order to determine if there would be any feasibility to either Option 2 or Option 3. EDC was not prepared at this time to simply write off the reserves in Block 47.
A Cost Effective Newbuild Semisubmersible Floating Production Platform
Authors: D&apos;Souza Richad , Cody Alan , Bauer Tom 
Published: October 2008

ABSTRACT
Semisubmersibie based Floating Production systems (FPS) have been extensively used in offshore field developments worldwide. Most have been converted from existing drilling semisubmersibies. Faced with a rapidly dwindling inventory of existing platforms to convert, the industry near cost competitive new build units. this paper presents the principles and development of just such a platform. It will be demonstrated that this new build platform is cost and schedule competitive with a conversion for a deepwater Gulf of Mexico development.

INTRODUCTION
Monohull or semisubmersible based FPSS converted from existing vessels, featuring low capital mat and cycle times to first oil, permit operators to economically develop small to medium sized fields in deepwater or remote regions [1,2]. Historically, field developments employing floating production systems were focused mainly in Brazil, West Africa the Far East and Australia. More recently, Operators in the U.K. and Norwegian sectors of the North Sea and Atlantic Frontier have accelerated the use of floating production systems to exploit their more remote, deepwater or marginal fields. This increase has been fueled by the growing confident and coat reductions in subsea and riser systems [3]. A case point is the development of the Njord field in the Norwegian North Sea by Norsk Hydro in about 1000 ft. of water by subsea tiebacks to a 45,000 tonne newbuild floating drilling production unit the Aker P45[4].
Semisubmersible based production or drilling and production units, in combination with subsea wells, have been used worldwide to commercially develop small to medium fields (50 to 100 million barrel reserves) in a wide range of water depth and environments [5]. With the exception of 3 newbuild units, most have been converted from second or third generation semisubmersible Mobile Offshore Drilling Units (MODUS) The availability of suitable candidates for conversion was never a problem, until recently. The soaring demand for deepwater exploratory and appraisal drilling has depleted the pool of candidate rigs for conversion and also raised acquisition prices.
There is a perception that a newbuild unit will cost a lot more and will have a significantly greater cycle time to first oil than a conversion. It is the intent of this paper to clearly demonstrate that a newbuild production semisubmersible, adapted from and employing the principles embodied in the Aker P-45 floating production unit can be eonunereially competitive with a converted semisubmersible FPS for a deepwater GOM application.

DESIGN APPROACH
Figure 1 illustrates the fimdarnental departure from the traditional approach to building semisubmersibles, that will achieve the design objectives of low cost and accelerated schedule for a newbuild FPS.
A Semisubmersible type Drilling, Early Production and Testing System with 100,000 bbl Storage for Deepwater
Authors: Nakamura Masahiro , Yokokura Kozo , Nakamura Arata 
Published: October 2008

Abstract
Deepwater petroleum development is increasing throughout the world. Complete evaluation of deepwater oil fields prior to development is extremely important but difficult due to harsh conditions and deepwater. Extended well testing and early production of a field will allow complete evaluation, reducing risk prior to long term commitments. Conceptual design andstudies for a semisubmersible type deepwater drilling, early production and testing system with 100,000 bbl storage (DEPTS) that will allow this have been completed. Needs analysis were performed and several potential concepts compared. Sizing and costing of the semisubmersible unit, mooring, and riser systems as well as selection of the drilling, production, and storage units were carried out. The unique aspect of the system is that the combination of drilling, production facilities, and storage on the same vessel will a How the system to be applied across the early phases of offshore oil field development from drilling to early production. With storage integrated into the vessel, oil production can continue in the most extreme conditions. The system's intended operational area will be the deepwater fields of Asia and Oceania. Studies have been carried out showing the technical and economic feasibility of the system in deepwater up to 2,000 m.

Introduction
The relentless trend of hydrocarbon exploration and development to deeper waters shows no sign of abating in the near future. Developments in 300m water depth are common, with the current deepest development being at 1027 m in the Campus Basin. Deepwater in the 2,000 m range is being explored, with the immediate question being which technologies are most appropriate for which fields. The large amounts of capital required for deepwater exploitation can lead to increased risk for the operators, necessitating measures to decrease risk, decrease overall development cost, or both.
The use of extended well tests (EWT) or easy production systems (EPS) can be used for reducing risk, optimizing full development design, and improving cash flow. For the purposes of this study, the following definitions were used:EWT: An EWT is used only to obtain production data and reservoir characteristics.EPS: An EPS is used to obtain early cash flow and increase a project's economic viability.
The usage of EWT or EPS can improve a project's overall viability in the following ways:The use of an EWT will reduce uncertainties about reservoir characteristic increasing the reliability of project economic forecasts.With better evaluation of reservoir production characteristics, the most appropriate exploitation concept may be developed and optimized, with possible corresponding decreases in total development cost and initial capital cost outlay.