bluuebunny/crossref_metadata_2025 huggingface dataset:
Fundamentals of 3D Seismic Volume Visualization
Authors: Kidd Gerald  D.
Published: October 2008

Since the early 1980's, the volume of 3D seismic data has been steadily growing. Beyond the increase in size and number of 3D seismic surveys, there is also proliferation of attribute data. This increase places additional demands on the interpreter that is difficult to meet using traditional mainstream interpretation methods. A key element in solving this interpretation problem is the application of 3D volume visualization, which introduces new technologies and requires new skills. It enables the geoscientists to extract tremendous amounts of information in short periods of time. To maximize benefits, skills in the art of volume visualization must be established. Grasping the fundamentals of 3D seismic volume visualization provides a foundation for growth and creative solutions. Essential fundamental concepts and visualization processes, namely the Zone System, are discussed with examples of its application on stratigraphic, structural and amplitude interpretation problems. Important interpretation considerations, and discussions on color, and key strategies for quality visualization are included.

Introduction

3D volume visualization is a method of seismic interpretation in which the interpreter directly evaluates the seismic reflectivity of the subsurface in three-dimensional space by applying various levels of transparency to the data. The technology and philosophy of 3D volume visualization1 differs from conventional interpretation and includes new interpretation strategies and methodology. Through direct integration of structural, stratigraphic and amplitude data, both regional and prospect-specific details can be revealed and evaluated prior to significant digital interpretation. This helps the interpreter to design an efficient work plan to achieve higher quality interpretations in a shorter period of time.

Visualization Types

There are two basic types of visualization: surface and volume. Surface visualization is the result of mapping individual horizons and faults, and then re-interpreting them collectively in 3D space as a 3D model. This method is time-consuming, involving two major interpretation steps and utilizes only a portion of the 3D data. Volume visualization assumes that the reflectivity of the subsurface provides enough detail to allow interpreters to directly evaluate and integrate structural, stratigraphic and amplitude features in 3D space. Both 3D regional and prospect-specific evaluations, including the identification of potential fluid contacts, can be performed quickly in detail. In contrast to surface visualization, a large percentage of the data volume is often evaluated.

Interpretation Considerations

In general, conventional interpretation methods produce maps, while volume visualization methods produce 3D perspectives. When the purpose of the task is specific, we normally make a map.
A Sea-to-Ground Magnetovariational Method
Authors: Patella D. , Mauriello P. , Siniscalchi A.
Published: October 2008

The magnetovariational (MV) approach consists of recording the natural time-varying magnetic field at two different levels below the ground surface. The MV method can also be used in marine researches using waterproof sensor devices. However, a weak point of marine measurements is the lack of stability of any sensor hanging in seawater. To overcome this difficulty, in this paper we propose an alternative array design consisting of a magnetic sensor device firmly laid down on the sea floor and a second device located on land at a remote station where the subsoil conforms to a 1-D structure. This circumstance and the uniformity of the primary magnetic field over largely extended regions allow the electromagnetic components in seawater to be readily estimated using the measured magnetic field at the remote station. By these estimates, the two-level MV response across the sea water layer can be definitively simulated. The same procedure can be adopted to simulate the magnetotelluric sounding at any level in seawater. Finally, the installation of a second remote station inland is suggested in order to minimize the effect of noise on the estimates of the apparent impedivity functions. Reliability and usefulness of the new sea-to-ground MV method are tested on two synthetic examples.

Introduction

A pioneering approach to magnetotelluric (MT) sounding with electric and magnetic sensors immersed in seawater at a depth of a few tens of meters dates back to the late 50s1. The recent technological progress makes now possible to carry out more sensitive offshore MT measurements with the sensors lying on the sea floor2.

An alternative approach to offshore electromagnetic probing is the magnetovariational (MV) method formulated by Patella and Siniscalchi3. They introduced an appropriate MV apparent impedivity (dispersive resistivity) function, which can be used to retrieve reliable impedivity structural models below the sea water layer. Basically, the MV method requires the recording of only the magnetic field at two different levels in seawater. Fig. 1 shows schematically a seaborne magnetic sensor layout. It consists of a pair of waterproof horizontal two-component magnetic devices, one of which is laid down on the sea floor in S(b), while the other is located close to the air-water boundary in S(t), vertically above S(b). A weak point of this array is the lack of stability of the top sensor device, which can be subject to a motional noise causing unpredictable corrupting effects on the magnetic channels.

Fig. 1-Scheme of the magnetic sensors configuration for the two-level magnetovariational method. (Available in full paper)
A Pneumatic Seismic Energy Source for Shallow-Water/Marsh Areas
Authors: Brede E.C. , Viger H.L. , Johnston R.C. , Sullivan L.B.
Published: October 2008

Non dynamite seismic energy sources have shown only limited success in difficult shallow water or marsh prospect areas, and none have shown applicability to both environments. Recently, a method has been devised to adapt a marine pneumatic source for operation in abrasive surroundings. A system composed of, four of these modified sources together with associated emplacement and retrieval mechanisms has been developed and has proven to be a reliable and efficient Seismic energy source for both shallow-water and marsh applications.

INTRODUCTION

During the last few years, numerous energy sources have been developed to replace dynamite as the primary means of generating seismic energy in offshore exploration for petroleum. One of these non dynamite sources is popularly called the "air gun". It has received wide acceptance by the exploration industry for work in both offshore and shallow-water prospect areas. In the latter case, the air guns are normally de played from a self-propelled, shallow-draft barge and may operate in water depths from four to forty feet.

When an air gun is suspended in water at depths of less than four feet, its acoustic output is severely degraded because of the proximity of both the bottom and the water surface. Under these circumstances increased acoustic efficiency can be effected by firing the gun on or the bottom. This procedure prevents the expanding air released by the gun from erupting through the atmosphere-water interface and thus eliminates a major source of acoustic energy loss. However, the entry of mud and sand into the gun during firing in this manner so accelerates the wearing of the gun exposed parts that reliability suffers. The substantial maintenance required on a marine gun during extended operations of this type makes the technique economically unjustified.

These difficulties have been overcome by the successful completion of a program to modify the marine air gun so that it operates reliably in both the shallow-water sub-bottom and the marsh. This modified gun is the heart of a four-gun self-contained energy source system that has been developed for operation in marsh and shallow water. The four guns of the system may be inserted up to ten feet deep into marsh of any foreseeable consistency in two minutes by hydraulically-actuated rams and withdrawn in a similar period of time. Sufficient air capacity is available to fire the guns up to 15 times in one location, retrieve the guns, move up to the next shot point and insert the guns, all within a lapsed time of ten minutes.

Comparison records obtained in the same prospect area with the modified guns embedded to various depths in marsh and marine guns fired in very shallow water clearly show the superiority of the "marsh" gun. The effect of varying the gun chamber sizes in the four gun array is shown by a record shot in the marsh with two different arrays.

How this system was developed - from qualifying the gun to results obtained with production system - is the subject of this paper.
A Variable Area Recorder for Offshore Seismic Data
Authors: Badger A.S.
Published: October 2008

The variable area display o£ seismic data has achieved practically universal acceptance by geophysicists for easy interpretation. In the past, survey recorders aboard ship displayed seismic data in a variable density mode using depth sounder instruments. This report describes a recorder capable of plotting offshore seismic data with rapid access to the recorded data and the visual benefits of variable area recording displays.

The recorder uses a new technique to permit slave operation from the energy source to initiate the display sweep. This permits variable cycle timing of the energy input without concern for the recorder mechanism.

The plot is made by galvanometers on direct write type oscillograph paper for viewing the section as the survey progresses. From one to four galvanometers can be used to record the seismic data. Timing lines are added coincidentally by a xenon flash lamp with .1 second and emphasized 1 second intervals beginning at TØ A crystal oscillator provides the stable time base for the timing line generation and synchronous motor drive as well. A magazine is provided for receiving the exposed section and is always used when film sections are made.

The plot is made on 10 inch wide paper using 9 inches of the surface for the data. Typical plotting speed is 2 inches/second for 4.5 seconds of data. The paper advances automatically at the end of the sweep and the mechanism resets in less than 3 seconds to await another input.

Field results of offshore data are displayed to show typical output of the recorder.

Introduction

One of the least documented subjects in the field of seismic exploration is that of data display. Volumes of material are written on the theory, the sources, processing techniques and results, but very little on the actual display of the information gathered. The man/machine interface is the ultimate result of all the effort and its importance should not be underestimated. The device to be described, is a variable area recorder for displaying offshore data in the form of a section plot that is accessable as the work actually progresses.

Rieber, in 1936, described a system for field recording using variable density photographic techniques adopted from sound-on-film work.1 This recording method did not receive wide spread adoption but was well known in the industry. A continuous profile of seismic data made from oscillograph film strips placed in sequence was described by Prescott in 1951.2. He remarks that a variable density or variable area oscillograph field record could be used but his displays were all of wiggle trace recordings. A step further in seismic section display was described by Palmer.3 This apparatus used variable density form of presentation from data recorded in the field on 70 mm film strips by variable density tracks. Time corrections were made to the data in plotting the variable density section and the results were of good quality. The use of film recording in the field was not widely adopted due to the emergence of magnetic tape recording techniques.
Salvage and Relocation of Offshore Platform with Minimum Equipment
Authors: McDonald William M.
Published: October 2008

This paper describes the planning and operations involved in the intact salvage and relocation of a five-well drilling platform in the Gulf of Mexico. The operation employed unique procedures to plug, abandon, and remove existing dry hole wells; to free the below-mudline portions of the platform jacket; and to minimize the size and amount of lifting equipment required. These planning and methods innovations resulted in a significant reduction in heavy lift equipment requirements, with a corresponding reduction in cost of the project.

INTRODUCTION

Humble Oil &Refining Company's South Pass Block 36 "A" Platform was originally erected in September 1963. This structure was a four-pile, five-well, tender type platform in 165 feet of water. It utilized a special five-well drilling rig sub-structure and derrick which required no rig skidding. The platform foundation jacket weighed 576 tons, and three 250 ton derrick barges were required to originally set it in position (Figure 1). Pertinent features of the jacket (Figure 2) included (1) four 34 inch O.D. main legs, battered 1 in 5, (2) a center 34 inch O.D.; combination non-bearing leg and conductor guide, (3) four 36 inch O.D., skirt pile guides, and (4) a 50 feet × 50 feet square, solid plate "shear box" attached to the bottom of the jacket and extending 28 feet below the mudline.

Drilling operations resulted in three unsuccessful wells, and the drilling rig was removed in August 1964.

In mid-1966 it was proposed to salvage the foundation jacket for reuse to support a new 62 man self-contained living quarters building in West Delta Block 73, where the water depth was the same 165 feet.

The salvage and re-installation of this structure presented four major problem areas which correspond to the four operational phases of the project.Well Abandonment and RemovalThree unperforated wells were left standing. Two required abandonment in conformance with governmental regulations. The required cement plugs had been placed in the third well by the drilling rig. All three had to be cut off below mudline, and if possible, removed prior to moving the jacket.Foundation Jacket RemovalThe dead weight of the jacket plus the frictional resistance of the "shear box" indicated an upward lift in excess of 800 tons would be necessary to remove the structure.Transport of Jacket to New LocationThree methods of transporting the jacket approximately 30 miles in semi-open Gulf waters appeared to be possible.The jacket could be set on a barge, and the barge towed to the new location. This would require over 500 tons of lifting capacity to re-install.The jacket could be made buoyant and towed in a horizontal plane.The jacket could be lifted vertically with the derrick barge crane, held with the crane, and the derrick barge towed to the new location.Installation at New LocationThe "shear box" created a problem at the new location. Although needed at South Pass, it was not needed and assumed to be extremely difficult to install at West Delta.
Sloping Sea Floors
Authors: Stanton P.N. , Tidwell D.R. , Lloyd J.R.
Published: October 2008

The effect of slope of the seafloor on the significant variables for multiline spread moorings with composite mooring lines containing both wire rope and chain has been investigated mathematically. A field test of the mooring calculations was conducted using an actual drilling vessel in the Santa Barbara Channel moored over a sloping ocean floor in water 1300 ft deep at the vessel and with anchors in depths of from 1056 to 1494 ft. The tests demonstrated the ability of the calculations to accurately describe the tensions in the tested lines.

INTRODUCTION

Floating drilling vessels use spread mooring systems to limit the horizontal offset from the wellhead that results from environmental forces acting on the vessel. In deep water, a spread mooring pattern may have anchors that are as far as two miles apart. In some areas, the ocean floor slopes sufficiently that the water depth can vary by several hundred feet from one side of a mooring pattern to the other. One such area is the Santa Barbara Channel, where the slope of the ocean floor sometimes exceeds 1200 ft/mile. Conventional mooring calculations for a flat bottom were considered inappropriate for these sloping bottom conditions. A numerical method accounting for a sloping bottom was developed and computer programmed. It accounts for all of the significant variables, such as mooring line tension, suspended line length, horizontal restoring force, and horizontal vessel offset; and it can handle composite mooring lines that contain wire rope and chain.

The equations used to relate the mooringline variables were derived from basic catenary equations. As the tension in a composite line consisting of both wire rope and chain increases, the equations describing the line change when the junction between the wire rope and chain is picked up from the sea floor or when the line becomes completely suspended. The equations were set up in a way that, with proper definition of variables, allows a single equation which is continuous and has continuous derivatives to apply for all ranges of tensions.

DESCRIPTION OF MOORING PROGRAM

Given an initial configuration of the mooring system, the computer finds the restoring force in pounds that will be produced by a prescribed horizontal offset of the vessel. This restoring force is equal to and opposite in direction to the steady environmental force acting on the vessel. The number of mooring lines, the mooring pattern, the initial tensions in the lines, a description of each line, the slope of the ocean bottom or the water depth of each anchor, and the depth at the initial vessel position must be given as input to the program along with the magnitude and direction of specified vessel offsets. As output, the program gives (at each offset) the tension in the most heavily loaded line, the suspended length of that line, the maximum anchor load, and the total restoring force exerted by the mooring system in response to the offsetting environmental force.
Artificial Upwelling
Authors: Roels Oswald A. , Gerard Robert D. , Haines Kenneth C. , Centeno Pedro A.
Published: October 2008

R.D. Gerard and J.L. Worzel of our laboratory have recently suggested pumping cold sea water from 1,000 meters depth through large diameter pipes into a condenser area located on shore to intercept the flow of moisture-saturated trade winds. This air, when cooled, condenses much of its moisture, which will be conducted to storage tanks for use as drinking water, avoiding brine pollution of the sea caused by conventional desalination systems. The deep cold water of the ocean is many times richer in inorganic nutrients necessary to initiate the photosynthetic process than the surface waters of the euphotic zone. The deep sea water, which has been utilized as a source of cold for moisture condensation, will flow into closed-off lagoons near shore, where it will act as a fertilizer to stimulate primary production. A pilot scheme is now under way on the north shore of St. Croix in the U.S. Virgin Islands, where deep water is less than one mile offshore and where we have conclusively established that the waters from the nutrient maximum (700 to 900 meters deep) will create a phytoplankton bloom. This, in turn, could sustain commercial yields of organisms such as shellfish, crustaceans, fish, etc. The cost of pumping could be offset by the production of energy by the Claude process and by other cooling applications, such as air-conditioning, ice-making, cooling of conventional desalination systems, nuclear reactors, etc.

Introduction

As population growth increases the pressure on our resources, we should more and more look towards the oceans for many of our needs and attempt to use their enormous potential in a rational way. A thorough understanding of the meteorological, oceanographic, geological and biological factors in the natural environment can help us in utilizing the sea to advantage rather than struggling to overcome the natural conditions and further pollute the oceans and adjacent shores.

Just as mankind in its history on land has gone through a hunting stage and has then slowly turned to agriculture for its food production by domestication of animals instead of hunting wild ones, and by cultivating crops rather than picking roots and berries growing wild in the forests, the day is here when we have started to plan marine harvests in a rational way.

The culture of mussels is now a large industry in Spain. Oyster culture has been introduced with varying degrees of success in different parts of the world. Shrimp farming is here, and fish are raised in many places now. The selection of breeding stock is a well-established science. However, to grow mussels, shrimp or fish, these animals must be provided with adequate food, usually algae. An early attempt to grow phytoplankton was made by the Pfizer Company in the New York area: Thacker and Babcock (1)* built a pilot plant for the mass culture of algae, which gave trouble-free operation over a period of almost a year (Fig. 1).
Gemini Subsea System Design
Authors: Beer Paul , Ribbeck Larry R. , Jefferies Andrew
Published: October 2008

Field development planning and execution is influenced by a number of different factors, but ultimately must be based on a project's ability to deliver the maximum economic benefit to the project partners while maintaining safety and environmental goals.

The Gemini development was executed as a fast track project with simultaneous appraisal and implementation tasks. This approach brings with it an inherent reduced scope definition which must be accommodated by the system design while still remaining focused on the project drivers.

The Gemini development reflects a sound project execution plan that accommodated significant unknowns while still delivering production ahead of schedule and improving on the capital cost expectations for the development.

Introduction

The Gemini prospect was discovered by Texaco with the drilling and testing of the Mississippi Canyon Block 292 Well No. 1 in the third quarter of 1995. Following the discovery, Texaco (60% GWI) and their partner Chevron (40% GWI) continued their appraisal process with two additional wells with sidetracks to investigate the original discovery and other deeper potential areas. Concurrent with the appraisal process, Texaco began preparations for a phased development of Gemini with an early gas development in the Allison reservoir.

In January 1998, both project partners received board approval to proceed with the early Allison gas development with a subsea tie back to a shallow water host facility. The facility selected based on location and expansion potential was VK-900 which is jointly owned by Texaco (25% GWI) and Chevron (GWI 75%, operator).

An integrated project team was formed to implement the project and a subsea equipment contracting strategy already established by Texaco was extended into the Gemini development. The subsea trees and control system under fabrication for Texaco's inventory program was adopted for Gemini to reduce the project cycle time with the goal of improving project NPV.

Project Drivers

The project team identified the following drivers for the development:The development wells could be clustered around the MC-292 Well No. 1 location to provide a single drilling center.Due to schedule requirements, the rig would be on location prior to the subsea equipment being ready for installation.A first production target date of July 1, 1999 was committed to by the project team.The system should consider the potential for future expansion in the area. This included sizing flowlines to meet the corridor development needs.The Ocean Star semi-submersible rig would be used due to long term contract commitments by Texaco. This would also be the primary installation vessel for the subsea equipment.System operability would be critical since an overall production uptime target of 90% was a development goal.

Field Layout

The subsurface team determined that the reservoir take points could all be accessed from the single drilling center at the MC-292 Well No. 1 location. Fig. 1 is an illustration of the local seafloor layout.
Fast-Track Development of Deepwater Kuito Field, Offshore Angola
Authors: Davison C. , Dyberg P. , Menier P.
Published: October 2008

This paper describes the development of CABGOC's Kuito field offshore Angola using an FPSO and subsea facilities. This field development marks the start of deepwater production off Angola, and is in addition particularly significant in view of the extremely short project duration from contract award to start of production. This was achieved while incorporating the highest international environmental standards, including the re-injection of produced gas.

Field Description and Development Plan

The Kuito field, which has an average water depth of 400 metres, lies in Block 14 offshore Cabinda. Block 14 covers some 1.5 million acres, with water depths ranging from 200 to 1,500 metres. CABGOC, as operator of Block 14, have also announced discovery of three other fields in the same block. Apart from CABGOC's 31% share as operator, Agip, Total and Sonangol have 20% shares each, and Petrogal has the remaining 9%.

The Kuito field was discovered in April 1997, and first oil was produced in December 1999.

The field development plan divides the development into two main Phases, 1 and 2, with Phase 1 itself being divided into Phases 1A, 1B and 1C.

Phase 1A is the first production phase of the field development, with surface production facilities consisting of a spread moored FPSO based on a converted VLCC tanker. The subsea facilities consist of 12 production wells produced via a subsea manifold, which is located at a distance of 1.9 statute miles from the FPSO. The manifold is tied back to the FPSO via two production lines, each with a diameter of 11", a test line with a diameter of 6", and associated gas lift and control umbilicals. Associated gas is used as fuel on the FPSO, and for gas lift of the production wells, with any unused amounts being re-injected, such that under normal operations there is no flaring.

Stabilised crude is pumped to export tankers via a CALM buoy offloading system. The CALM buoy is located 1.15 statute miles from the FPSO and connected to the FPSO via two flexible flowlines, which each have an internal diameter of 15". A schematic of the Phase 1A field layout is shown in Figure 1.

Phase 1B covers Water Injection facilities, with seawater treatment and pumps already provided on the FPSO, and a 10" flowline and control umbilical leading to an 8-slot manifold.

Phase 1C will consist of an additional subsea production centre, similar to the 1A arrangement.

Design life for the FPSO is 10 years, with all other field facilities and FPSO mooring system having a design life of 25 years.

As of January 2000, Phase 1A is producing through 7 wells, with the remaining trees in the course of being installed and hooked up. Phase 1B is in the course of development with the start of operations set for second quarter 2000, and Phase 1C is at the engineering and evaluation stage.

Consortium Arrangement
Economics & Case Study of a Change to Big Bore Wells
Authors: Landrum William R.
Published: October 2008

This paper describes a field development program from its inception through the first year of production. Part way through the construction phase, engineering evaluations indicated that a change in the development plan to all big bore wells would accelerate oil production and improve project economics. Approval was gained for the change in basis of design from smaller well bores to all big bore wells. Actual production data was tracked. Well performance and economic analyses were performed to post audit field and well results. The value of changing to big bore wells was then easily quantified.

In the early engineering and construction phase of the development, nodal analyses showed that production well performance could be increased from a well rate of 20,000 BOPD (3180 m3/d) to more than 30,000 BOPD (4770 m3/d) with a change from 5-1/2" tubing and tree to a larger 7" size. A reservoir model was run with production ramp-up to plateau to feed into an economics model. At the same time, operational concerns over the size change were voiced and probabilistic economic simulations were run to take into account the potential for additional trouble or down-time accompanying operations during the installation of the larger 7" equipment. Economics were favorable.

Approval was granted by management and a special resolution passed by the Unit Technical Committee to change the basis of design from 5-1/2" tubing and tree to 7". This change proved to be a major factor in the successful start-up and profitability of the development. Production wells began producing at a rate of 40,000 BOPD (6360 m3/d) each, with one exceeding 46,000 BOPD (7313 m3/d). This would not have been possible with the smaller tubing size. The net present value (NPV) from accelerated production improved overall project economics by more than $108 million due to the change to big bore wells.

Field Information

The Heidrun Field in the Haltenbanken Area offshore mid-Norway, was discovered in the Spring of 1985. The field lies 118 mi (190 km) from the Norwegian coast in 1150' (350 m) of water. The appraisal program of 7 wells proved oil and gas in the 3 major reservoir units of the Middle Jurassic Fangst Group and the Lower Jurassic BÅt Group which is differentiated into the Tilje and Ã?re formations. The field contains 2.785 billion STB (443 million Sm3) of oil in place, 1 billion STB (159 million Sm3) of recoverable oil, 1.592 billion SCF (45 billion Sm3) of gas in a gas cap, plus more than 1.386 billion SCF (39 billion Sm3) of solution gas. The field contains a 656' (200 m) oil column and extends over an area of 9400 acres (38 square km).

The Heidrun Field was mapped based on 3D seismic data acquired in 1986. A variety of methods and types of data were employed in generating the geologic model of the field including wavelet processing of the 3D seismic data to enhance the reservoir description, extensive correlation studies, and field studies on outcrops of analogous sediments exposed in East Greenland.
Sassan Field A Case of A Major Offshore Production Operation in the Persian Gulf
Authors: Dietzel Norman E. , Freeburg Edward A.
Published: October 2008

Lavan Petroleum Company (LAPCO) was formed in April 1965 as a joint structure operating company, one-half owned by the National Iranian Oil Company and one-half owned equally by four American companies: Atlantic Richfield Company, Murphy Oil Corporation, Sun Oil Company, and Union Oil Company of California. On August 31, 1965, Well 2S-l was spudded in one of three offshore Persian Gulf tracts explored by LAPC9, and later proved to be the discovery well of the Sassan Field with no existing production operations and only a drilling and exploration staff, LAPCO embarked on a program to design, install, and commission this major offshore production operation. The resulting facilities, capable of producing and handling 220,000 barrels of oil per day, were on stream by June 1968. Consultants and contractors were used for nearly all phases of evaluation, engineering, design, and construction.

The development plan for Sassan Field included several unique features more or less forced upon LAPCO by the Axtent and location of the field. These include:

1. Individual well structures and flowlines, in water" depths of 68 to 100 feet.

2. High throughput of live oil with no surge capacity on the offshore flow station.

3. An 88 mile, 22 inch diameter pipeline between the field and Lavan Island through water depths up to 306 feet.

This paper emphasizes the importance of effective planning to achieve a rapid development and installation of a major crude producing, handling, and loading complex, both onshore and offshore. It also demonstrates that even the best of planning cannot anticipate all eventualities and that some delays and extra costs are unpredictable in a project of this magnitude.

Introduction

The story of the Sassan Field may be said to date from the 5th century A. D., for at that time its namesake, the Sassanian Dynasty, was at the height of its ruling power over all of ancient Persia. Fifteen centuries later, the "modern" Sassan story began when a Joint Structure Agreement became effective February 13, 1965 between the National Iranian Oil Company (NIOC) and four American oil companies: Atlantic Richfield Company (the coordinator), Murphy Oil Corporation, Sun Oil Company, and Union Oil Company of California. This Agreement led to the creation in April 1965 of Lavan Petroleum company (LAPCO) as the operator. This new company was charged with the exploration, development, and exploitation of three tracts in the Persian Gulf totaling about 8,000 square kilometers. (See Illustration No.1.)

LAPCO's initial well, No. 2S-l, was spudded on August 31, 1965, and in November, a drill stem test yielded crude oil from a formation at 7968 feet which was eventually tested at 7788barrels of oil per day (BOPD). through 3-1/2 inch drill pipe and clearly established this as a commercial well. By December when the well was completed, there was little doubt that LAPCO would soon be developing a major offshore production operation.
Quantifying Fluid Prediction Using Angle-Dependent Inversion Measured Against Log Fluid Substitutions
Authors: Anderson James W. , Bogaards Mark A.
Published: October 2008

A Bright spot prospect was identified using 2D and 3D seismic. Due to the isolation of this prospect from existing infrastructure it is critical to be able to predict the type of hydrocarbon likely to be present. The approach taken to quantify hydrocarbon type included the following steps:reprocess a 2D seismic line which connects the well control to the prospect,use the well to model the response of different pore fluids in the reservoir quality sands,perform incident angle dependant inversions of the 2D seismic,statistically quantify and compare the results from the prospect with the model results,use the fluid probability at the prospect in the project risk assessment.

We know that normal incidence seismic data is the response to the acoustic impedance, AI, of the geologic layers. However, at non-zero incident angles, the seismic data is the response to the elastic impedance1, EI, of the geologic layers. Because of the inherent pitfalls of using amplitude variation with offset2, AVO, a new approach was taken to quantify the fluid at the prospect. First, a pre-stack time migration of a 2D seismic line was created followed by near and far angle stacks. AI and EI volumes are then generated for the respective angle stacks. This process is called angle dependent inversion, ADI. AI and EI values are extracted for each CDP within the prospect.

Log-based fluid substitution3,4,5 models are created to establish a range of AI and EI values for reservoir quality sands. Each model is displayed as a probability distribution function, PDF and compared to the extracted ADI values. The results indicate that it is unlikely that the prospect sand is brine filled. The most probable hydrocarbon in the prospect reservoir is gas.

Introduction

A deepwater Gulf of Mexico prospect was generated in which high amplitude seismic events were used to define the areal extent of a potential reservoir. The location of the prospect is over 30 miles from the nearest host platform. It was assumed that a single subsea completion would be used to develop a discovery. However, it was quickly realized that given the estimated volume of the reservoir and the tie back distance a gas discovery would be very commercial while an oil discovery would be equivalent to a dry hole. Trend analysis of the surrounding fields was not conclusive in predicting the most likely hydrocarbon type at the prospect. Therefore, a study was conducted in which modeled acoustic and elastic impedance for varying reservoir fluids were compared to extracted values from near and far angle seismic inversions in an attempt to predict the fluid type in the prospect.

Although the prospect was mapped using a 3D data set it was concluded that a single 2D seismic line through the prospect would be sufficient to make the fluid prediction. A recent-vintage 2D line was selected that went through the center of the prospect and within 500 feet of our primary well control (Well 1).
Setting Up New Ventures in West Africa
Authors: Lorenz Jeannot C. , Lorenz Alexis R.
Published: October 2008

The main application for this paper is for businesses looking to locate in the region to gain a basic understanding of the general requirements to be successful in West Africa, primarily in Angola. The secondary application is for various businesses to use the paper as a framework for evaluating whether suppliers in the region are indeed, well established and thus able to successfully operate and fulfill contracts. It will, in particular, address the challenges of building an organization where the political, economic and social cultures are quite different than that of the United States. The paper will review the necessary skill set of key personnel within the organization, which is needed to operate successfully in a diverse environment. We will also examine the challenges of lack of infrastructure with regard to conducting daily business and maintaining operations as well as winning contracts.

New Discoveries in West Africa

The latest figures for West Africa indicate a bounty of deepwater opportunities. Nigeria currently produces two million barrels per day and recent discoveries will push the figures even higher. The Congo Basin is also proving to be quite impressive. With the Chevron, Elf, BP/Amoco and Exxon deep water discoveries in Angola, the region has never looked so promising as noted in the Financial Times newspaper earlier this year. The paper cited Angola as "one of the world's most exciting oil frontiers and two-thirds of deep water exploration wells have struck oil, compared to a historical world average of closer to 15 percent." Consultants have predicted that Angola's current production of 800,000 bpd will increase to 1.4 million bpd by the 2005. Others have predicted that production could rise to 2.5 million bpd by 2015 surpassing Nigeria to become Africa's largest oil producer.

Even with the lure of the huge potential in West Africa, many companies still shy away from the region. It is not without good cause that companies are reticent about starting up operations in West Africa. Despite the trepidation, companies can and do thrive in the region. The aim of this paper is to provide sound advice for you and your company to succeed in this exciting region of the world.

The Pioneers and the Emerging Market

In the beginning, there are always those brave souls willing to venture forth to set-up shop in the far corners of the world. The first task for the pioneer is to verify market information available through various commercial sources.

Testing the market is the primary mission for the pioneer. If the products or services do not add value to the market, there is no point in going any further. Testing the market is not a simple procedure in Angola. One must take time talking with national oil company managers, potential clients and suppliers. Flying in for a week and flying out will not render the needed information.
Trends In The Steels Used In Merchant Shipbuilding
Authors: Crum Frank J.
Published: October 2008

With the increase in the size of modern merchant vessels, as well as changes in design and increased plate thicknesses, there has been a growing interest in the use of higher strength steels for ship construction. The history of hull steel specifications following the advent of welded construction is discussed, together with present American Bureau of Shipping requirements for both ordinary and higher strength steels. Some precautions that are considered particularly necessary when welding on higher strength steels are also presented. Since mobile offshore drilling units are now being classed by the Bureau, the owners and designers of such structures may find the discussions included in this paper of interest.

INTRODUCTION

As everyone closely connected with the shipbuilding industry is aware, the present trend toward the use of higher strength hull steel is increasing and it appears to be increasing at a rather rapid rate. As the size of merchant ships continues to grow and as the size and number of hatch openings in cargo vessels and ore carriers increase, it has become necessary to use heavier plating of ordinary strength steel, which in some cases approaches 2", in order to meet strength requirements. There has been reluctance to use plating of excessive thickness since investigations on the brittle fracture problem have indicated that, in addition to metallurgical considerations, there are "size effects" which adversely influence notch toughness as the thickness of the plating is increased.

The primary advantage of higher strength steels is that they allow a reduction in plate thickness which tends to minimize "size effects" and which results in a ship of lighter weight and greater load-carrying capacity for a given size vessel. Depending on the needs or wishes of individual owners and the size or type of vessel they choose to build other advantages may be (1) greater speed (2) lower fuel consumption(3) a smaller size propulsion unit or (4) improved stability through reduction of top-side weight. The use of lighter gage plating during construction offers the further advantages of (1) lighter sub-assemblies to handle (2) less man-hours of welding and (3) lower electrode consumption. Some of these economic advantages are offset however to some degree by the higher cost of the steel and electrodes, possible replacement difficulties and the refinements or improvements that may be necessary in design, workmanship and inspection. It is, therefore a decision of individual owners and designers whether to use higher strength steels and to what extent.

Although higher strength steels are now being used rather extensively they are not entirely new in merchant ship construction and have been used in Naval vessels for a number of years. Higher strength steels were used with satisfactory results on such vessels as the SS "United States" built in 1952 on the SS "France" and several ore-oil carriers built in 1962, and on a few vessels strengthened for navigation in ice.
Prediction of Static Bearing Capacity from Wave Equation Analysis
Authors: Coyle Harry M. , Bartoskewitz Richard E. , Lowery Lee L.
Published: October 2008

The purpose of this paper is to present the results of a study which involves the prediction of the static bearing capacity of a pile from a wave equation analysis of piling behavior. Recently developed soil parameters including point damping, friction damping and quake are used in the computer solutions of the wave equation analysis. Also, the wave equation program is modified so that velocity may be raised to a power less than 1 in order to insure constant damping effects.

Curves of total static soil resistance at the time of driving vs pile penetration resistance in blows per foot are developed. Different curves are generated for different distributions of total soil resistance between the side of the pile and the tip and for varied soil parameters. These curves are compared with similar curves developed using E. A. L. Smith's recommended soil parameters.

Using the computed curves and the knowledge of pile penetration resistance during the last foot of driving, the static bearing capacity of the pile is predicted. These values of pile capacity are compared to actual values determined full-scale static load tests made in the field.

INTRODUCTION

In 1960, Smith7 presented a mathematical model to simulate pile-soil interaction. At the same time he proposed a numerical method for analysis of piling behavior based upon the one-dimensional wave equation. Smith' s model idealized the pile as a series of masses and springs as shown in Fig. 1. The load deformation characteristics of the soil as shown in Fig. 2 are described the parameters Ru, Q, J, J1 and V, where

(available in full paper)

The total soil resistance mobilized during dynamic loading was given by Smith as:

(available in full paper)

Research personnel at Texas A&M later modified Smith's original equation so that the velocity term is raised to a power [N]. 3,4,6 Eq. 1 is rewritten as:

(available in full paper)

When Smith's paper was presented in 1960, factual information concerning the magnitudes of the damping constants and J1 were virtually unavailable smith recommended parameters of 0.15 and 0.05 for J and J1, respectively. He also recommended a value of 0.10 for the parameter Q. Smith based his recommendations mainly on the strength of his own field experience with the piling behavior problem.

Recent research conducted at Texas A&M has resulted in What is believed to be more representative values for the parameters Q, J1 and J.3,4,6 The values obtained are presented in Table 1. There values are based mainly on the work of Korb,4 which involved small-scale dynamic and static pile loading tests in a variety of soils.

Parameter Study Using Field Test Data

The computer program for solving the one-dimensional wave equation is used to generate a curve relating total static soil resistance at the time of driving to the driving resistance expressed in blows per foot.