bluuebunny/crossref_metadata_2025_split huggingface dataset:
Ceiba Field Development: Fast Track to Early Cash Flow Management's Perspective
Authors: Garrett Marvin M. , Drinkard Don M. 
Published: October 2008

Abstract
The Ceiba Field development offshore Equatorial Guinea has proven to be a success for Triton and its partners Energy Afric aand the Ministry of Mines and Energy of Equatorial Guinea. A brief background of the Ceiba Field will be presented, however the main focus of the paper is Triton management's perspective of the development. Management's objectives for the project will be discussed, as will the phased approach to development. This approach led to use of an early production system to develop a major deepwater field on a fast track basis. The management perspective will detail the project drivers and achievement of the desired results.

Introduction
Triton Equatorial Guinea, Inc.'s discovery of the Ceiba Field in October 1999 opened the door for the company to build a sizable business in West Africa. With an entrepreneurial organization and flexible operational philosophy, company management put Ceiba development on a fast track, targeting an aggressive timeline for the project that moved from discovery to cash flow in 14 months. The company employed a phased approach to realize the opportunity presented by Ceiba. Parallel processes and off-the-shelf technology were utilized to optimize field production and the value of Triton's holdings while managing risk.
The Triton team completed the first development phase (Phase 1) and achieved first Ceiba production in November 2001. Full field development infrastructure for the Ceiba project (Phase 1A) was completed in January 2002, with the promise of more solid development ahead.

Equatorial Guinea: Prolific Oil Stronghold
Equatorial Guinea, where Triton (acquired by Amerada Hess Corporation in August 2001) strongly believed there was substantial opportunity offshore in deep water, ranked high among the company's drilling prospects. The Republic of Equatorial Guinea lies in the heart of the active West Africa region. It has been a country of growing interest to E&P companies since the first major discovery was made there in the mid-1990s. This small Spanish-speaking country comprises Bioko Island, the home of the capital city of Malabo, and the Rio Muni area on the mainland.

Great Discovery Well
The foundation for the Ceiba project was a great discovery well. Ceiba-1 was drilled to a total depth of 9,700 feet in about 2,200 feet of water on Block G about 22 miles offshore Rio Muni. Wireline logs and other test data indicated a gross oil column of 742 feet and 314 feet of net oil-bearing pay in four zones. The high-quality turbidite reservoirs have excellent porosities ranging from 20%-30% and permeabilities up to 1 Darcy. This excellent reservoir was confirmed with a well test of 12,400 BOPD of 30 degree API oil from one zone.

Ceiba-2 Proves Commerciality
Triton's next mission was to appraise Ceiba to prove its' commerciality while proceeding with development planning that anticipated success. With the thickness and quality of the Ceiba reservoirs, it was easy to set the development on a fast track.
Ceiba Field Subsurface Considerations
Authors: Weaver R.A. , Dailly P.A. , Lamar A.T. , Lowry P. , Mees C.G. , Monson G.D. 
Published: October 2008

Abstract
This paper describes some of the subsurface considerations that were involved in Triton Equatorial Guinea, Inc. (Acquired by Amerada Hess Corporation in August 2001) rapid development of the Ceiba field.

Introduction
The Ceiba Field is located offshore Equatorial Guinea approximately 75-km southwest of the port city of Bata and 275 km south of the city of Malabo (Figure 1).
The Ceiba Field was discovered in September 1999, with the drilling of Ceiba-1. The first appraisal well, Ceiba-2 was drilled in November 1999 approximately 1.6-km southwest of Ceiba-1. Ceiba-1 and Ceiba-2 were drilled based on interpretation of 2D seismic data acquired between 1984 and 1998. Open-hole logs, cores, pressure data, and a DST of Ceiba-1 indicated that both wells contained Cretaceous sands of very high quality, capable of producing high rates of oil. Ceiba-1 was drill stem tested at rates as high as 12,400 barrels of oil per day. Ceiba-2 was not tested because of the excellent reservoir quality indicated from the open-hole logs, cores, pressure data, and the oil samples recovered. Figure 2 shows the general stratigraphic section from the Rio Muni Basin, which was encountered in both wells.
In December 1999, the Ceiba Field Plan of Development Phase 1 was submitted to the Equatorial Guinea Ministry of Mines and Energy. The Plan detailed the work necessary for early, initial production from the Ceiba Field. The Plan of Development Phase 1 was approved in December 1999.
A 3D seismic survey was completed over Block F and Block G in March 2000. A portion of the survey that encompasses the primary Ceiba reservoir was processed and interpreted to determine the location of appraisal wells necessary to confirm the extent of the field. Results of the 3D seismic survey were used to select the placement of three further appraisal wells, Ceiba-3, Ceiba-4 and Ceiba-5.
These additional appraisal wells were drilled in June and July of 2000 and confirmed the presence, connectivity, and quality of the reservoirs encountered in the Ceiba-1 discovery well. The locations of the drilled wells are shown on Figure 3.
Concurrent with the drilling of the appraisal wells, construction of an early production system consisting of a converted oil tanker was initiated. In November 2000, only 14 months after initial field discovery, the Sendje Berge FPSO was installed in the Ceiba Field and production commenced from the Ceiba-2 well.

Geologic
Ceiba Field is located on the present day continental slope in approximately 700m of water. The depth to the crest of the structure is approximately 2125mSS at the Top Campanian reservoir level. The depth to the free water level is 2471mSS giving the field a gross-oil-column-height of 346m. The field sits within a NE-SW trending belt of salt-cored structural highs, interpreted as base of slope compressional features, in the Rio Muni Basin.
Images of the Base of Gas Hydrate Stability, Northwest Walker Ridge, Gulf of Mexico
Authors: McConnell Daniel R. , Kendall Beth A. 
Published: October 2008

Abstract
The gas hydrate stability zone, the zone below the seafloor where gas and water should form gas hydrate is predicted to be present in the tophole sections in deepwater areasaround the world including the deepwater Gulf of Mexico. Few, if any, bottom simulating reflectors (BSR) or other manifestations of the gas hydrate stability zone have been interpreted in the Gulf of Mexico. This paper presents convincing images of the base of the gas hydrate stability zone extracted from exploration 3-D data in Northwest Walker Ridge in the Gulf of Mexico from the upper 1,050 m of sediment. This area is on the margin of an uplifted and compressed mini-basin and in the vicinity of numerous giant gas mounds at the seafloor. Interpreted tophole stratigraphy includes laterally extensive, steeply dipping basin floor silts and sands. This paper shows images of hydrate-trapped gas at multiple reflectors at depths that are coincident with the predicted base of the hydrate stability zone if modeled with a geothermal gradient of 19.6 ± 0.5 °C/km. A BSR is seen in the seismic data in vertical section, but the more convincing images of the base of gas hydrate stability are seen in map view.
We expect that the subsurface conditions here are not unique and the hydrate stability zone is similarly imaged, but perhaps has not been recognized, in similar settings in other parts of the Gulf of Mexico and elsewhere in the world.
Recognition of hydrate-trapped gas can aid in better decision making for shallow-gas avoidance strategy for exploration drilling and optimal design and placement of conductor strings for deepwater development wells. The possible concentrations of gas hydrate reservoirs in the updip margins of hydrate traps should also be of interest to those that are evaluating the feasibility of commercial exploitation of gas hydrates.

Local Geologic Setting
Figure 1 shows the study area in the northwestern part of Walker Ridge in the Gulf of Mexico. The focus of the study is in an uplifted and compressed minibasin with giant gas mounds to the northeast and a large salt wall with shallow buried salt or salt cropping out at the seafloor to the south. Thrust faults within the mini-basin have seafloor expression (Figures1 and 2). The source of compressive stress is apparently from shallow salt movement north-to-south on the northern margin of the minibasin. A larger, deeper salt withdrawal basin (not shown) is oriented northwest-to-southeast, northeast of the giant gas mounds. Both of the salt withdrawal basins filled with Pliocene and Pleistocene sediments transported from the shelf-edge towards the central Gulf of Mexico Basin. The minibasin is filled with typical deepwater sedimentation cycles composed of debris flows, basin floor splays, channels, thin turbidites, and hemipelagic clays.
Ils- A Passive Insulation Solution To Answer Cool Down Time Challenges On Deep Water Flowlines
Authors: Hallot Raymond , Couprie Stephane , Chomard Angele 
Published: October 2008

ABSTRACT
Flow assurance issues are driving more and more the design of Deep Water Flowlines, and Cool Down Time requirement has a major impact on the global system design for most West African subsea field developments.
A new thermal insulation solution has been developed, named ILS (Liquid solid Insulation), based on the use of phase change materials (PCM). This paper presents the principle of the ILS solution and the main results achieved through the development program, from the theoretical analysis to the qualification tests.
In normal flowing conditions, the PCM liquefied by the oil's heat flux acts as a heat accumulator. During production shutdowns and resulting cool down, the phase change material's crystallization restores partially this stored heat to the flowline. Therefore, such an insulated coating produces a significant thermal inertia to the flowline and the cool down delay before hydrates formation is 2 to 4 times longer with regard to the existing insulation technologies.
Due to the incompressibility, the low density and the low cost of chosen phase change materials, ILS is able to deal with deepwater & ultra deepwater flow assurance requirements and to compete with existing pipe-in-pipe or syntactic thermal insulation.

INTRODUCTION

Deep offshore flow assurance issues
It is now obvious that construction and exploitation of deep sea and ultra deep sea offshore fields induce specific and novel concerns, with regard to conventional shallow water offshore. One of the more critical problems is flow assurance at such water depths, for both steady state production and shutdown / restart conditions.
The first deep sea flowlines characteristic is their need to be efficiently thermally insulated, in order to preserve a sufficient production temperature on the FPSO topsides, and also to avoid solid deposits on the pipe wall : actually, deep offshore fields whose exploitation is forecast to be profitable are often spread over very large areas, which implies longflowline layout on the sea bottom, in low temperature sea water. Moreover, due to the depressurisation inside high deep offshore risers, the gas phase expansion and the light cuts vaporization produces a severe cool down ofproduced effluents.
Another specific concern about deep sea flowlines is the risk of gas hydrate plug formation, at relatively high temperature under high pressure, especially during production shutdown and restart episodes. The cool down time to reach the hydrate formation temperature in shutdown condition is a major requirement of deep sea flowlines ; it must be sufficient enough to allow the completion of flowline emptying operations, or to start a dedicated heating feature.
In order to fulfill these requirements, the current or emergent technical solutions can be sorted in the following two categories :
Passive thermal insulation : Pipe-in-pipe technology or syntactic foams, ensuring simultaneously the insulation function and the cool down time function.
Controlling Hydrocarbon Fires in Offshore Structures
Authors: Chamberlain G.A. 
Published: October 2008

Abstract
This paper reviews improvements in the understanding of fire hazards and protection in offshore structures since the Piper Alpha disaster in 1988. Important new knowledge on fire development, spread and escalation have come about through a number of industry sponsored initiatives, which have also demonstrated how to control and mitigate fire hazards by good design and effective protection. The most notable gains in knowledge have been in the areas of unconfined two-phase hydrocarbon jet fires, confined jet and pool fires (compartment fires), and understanding the value of area deluge for fire mitigation.

Background
The Piper Alpha disaster was a tragic milestone in influencing the Safety Case regime [1]. Since then there have been a number of Industry sponsored initiatives, which have contributed to significant advances in the science and understanding of the consequences of accidental hydrocarbon fires in offshore structures and the engineering of safe design. While some uncertainties remain, the application of this knowledge, via a Hazards and Effects Management Process or appropriate Standard (e.g. ISO 13702:1999), is normally sufficient to improve design and operation of plant in a cost efficient way.
A short review of the fire hazard aspects of the Piper Alpha disaster helps to focus on credible scenarios. Next to each event are some pertinent questions asked of the main fire hazards and the effectiveness of possible protective barriers that could be brought to bear in safety studies and design:The initial blast ruptured oil lines in the adjacent module. How severe was the resulting fire? To what extent does the surrounding congestion and confinement affect the severity? How toxic is the smoke?The Tartan riser failed on the outboard side of the emergency shut-off valve resulting is a full-bore jet fire. What protection should be applied to risers and valves? Is passive fire protection (PFP) adequate? Will PFP age with time and then be less effective against fires? Is a sub-sea isolation valve effective against rise fires? How close to the platform should it be located?The water deluge system did not operate. How effective are water-based systems in controlling different types of fire?How effective are blowdown systems against different types of fire? What strategies should be adopted? The Blast and Fire Engineering for Topside Structures (BFETS) Project [2,3] started in 1990 was the first major initiative to provide interim guidance on how to reduce the potential for such disasters. This project also identified gaps in knowledge and recognized the need for full-scale experiments and further guidance, which have been addressed in numerous follow-up studies and other Joint Industry Projects. In this paper I review the considerable progressmade to address the questions raised above.

Fire Hazards
An accidental release of flammable hydrocarbon results in a variety of fire consequences, dependent on the type and initial state of the hydrocarbon.
Vessel to Vessel Fluid Transfer Line Alternatives and Costs for the Gulf of Mexico
Authors: Mungall J.C.H. , Mattern M.A. , Bhat S.U. , Compton C. , Jackson D. , Steube C.H. , Noble P.G. 
Published: October 2008

Abstract
The transportation of stabilized crude by shuttle tankers instead of by pipeline offers cost and market flexibility advantages. The stabilized crude is stored on an FSO for periodic offloading to shuttle tankers. Fluids are transferred between Dry Tree Units (DTUs) such as Tension Leg Platforms and Spars and the FSO by means of Fluid Transfer Lines (FTLs). Additional cost benefits can be obtained by splitting the facilities between weight sensitive Dry Tree Units and the FpSO. An overview is presented regarding the practicality, cost and selection of vessel to vessel FTLs for use in the Gulf of Mexico. Four different FTL configurations are investigated: Flexible and steel W-Wave (near-surface) risers, Flexible Freehanging catenaries, and a Steel Catenary Riser (SCR) and Steel Lazy-Wave Riser (SLWR) combination that extends to the seabed. Installation and material costs are presented. Attention is focussed on flow assurance-especially as regards pipe sizing and insulation requirements. A base case is selected, and sensitivity studies are carried out for three vessel separations and for three water depths.

Introduction
The conclusions of the 2001 OTC paper on shuttling in the Gulf of Mexico serve as a starting point for this paper, (Ref. 1).
The conclusions were that:Given the current world energy market and the US demand for energy resources, deepwater exploration in the Gulf of Mexico (GOM) will continue at a rapid paceThe active GOM exploration programs will likely identify substantial discoveries spurring field development technology.These discoveries will be located further from existing field infrastructure requiring additional existing infrastructure and development of new transportation systems.Shuttling is a proven offshore transportation technology that is in use globally operating in both benign and harsh weather conditions.Both pipeline and shuttling transportation systems will be essential to meet the volume requirements of the Gulf of Mexico and energy demand of the US.
The type of field layout that is particularly suited to the employment of shuttle tankers is shown in Figure 1. The goal is to minimize DTU cost by placing as much of the processing facilities on a FpSO. The storage offers the developer the option of offloading stabilized crude to a shuttle tanker-increasing infrastructure independence and lowering cost, while avoiding the need to tie into an oil export pipeline system. (There is still the need to tie into a gas export pipeline system.)
One of the keys to reducing costs is to transfer the maximum amount possible of facilities from the DTUs to the FpSO on account of the reduced cost of FpSO "real-estate." This requires the presence of FTLs, for which there are a number of alternatives. Separations between the platforms can be significant because the FpSO must be turret moored. The separations will be of the order of 2000m or 3000m unless the vessels are coupled through their moorings.
Failure Analysis of Texas Tower No. 4
Authors: Jin Z. , Bea R. , Sharples B.P. Malcolm 
Published: October 2008

ABSTRACT
The Texas Towers were a series of platforms installed off the U.S. East coast in the 1950's to support early warning radar facilities. Texas Tower No. 4 (TT4) was installed in a water depth of 185 feet in 1957. At this time, TT4 was heralded as an ‘engineering marvel’, a major innovative ocean engineering accomplishment. However, problems in the structural integrity of the platform developed after the installation. In spite of vigorous efforts trying to save the platform, TT4 failed during a storm in January 1961 with the loss of the lives of all 28 personnel that were onboard at the time. This was one of the famous incidents during the early age of Ocean Engineering. In 2000, a study was undertaken by the authors together with the American Bureau of Shipping who pooled their resources of information and insights into platform behavior and experience to revisit the failure of TT4. The objective of this study was to see if with modern ocean engineering technology (storm forces, structure capacities), the details of failure of the structure could lead to a better understanding of behavior of current platforms where there is a paucity of actual failure. This paper summarizes the results from this study and the associated study of human and organizational factors in the life-cycle of what was, at the time, an innovative deepwater structure.

INTRODUCTION
The Texas Towers were a series of platforms installed off the U.S. East coast in the 1950's to accommodate early warning radar facilities. Texas Tower 4 (TT4) was installed in a water depth of 185 feet in 1957. At this time, TT4 was heralded as an ‘engineering marvel’; a major innovative ocean engineering accomplishment. But, shortly after it was installed, unusualmotions and sounds were reported by personnel onboard the platform. Studies were commissioned to measure and analyze the dynamic motions. The second author was a graduate student at this time and assisted with the analysis of the motions of TT4 conducted by Brewer Engineering Laboratories[6].
Studies of the dynamics indicated that bracing and joints were not as effective in stabilizing the platform as had been anticipated during the design of the platform. Pinned joints and some damaged braces were identified as likely responsible for the excessive motions. Underwater inspections later confirmed these results and supplemental bracing was installed in an attempt to stabilize and strengthen the platform. In September 1960, a hurricane further damaged the platform; fracturing underwater braces and joints. In December 1960, the decision was made to evacuate TT4 for repair, but before this could be done the platform was hit by a winter storm in January 1961 and collapsed into the sea with the loss of the lives of all personnel onboard.
Subsequent to the failure, extensive underwater surveys identified many of the factors that were responsible for the failure of TT4. These were presented into a Congressional Committee hearing evidence investigating the collapse[1,2,3].