bluuebunny/crossref_metadata_2025_split huggingface dataset:
Pompano Subsea Development - TFL Well Design for Deepwater Unconsolidated Waxy Oil Reservoirs
Authors: Holt J. , Black J.W. , Meader A. , Whitehead N. 
Published: October 2008

Abstract
BP Exploration's Pompano subsea development, in 1865 ft of water uses a subsea production system to produce oil to a host platform 4.5 miles away. This paper describes the well construction and completion design for a template/manifold Through Flowline (TFL) subsea oil production system. Including are an outline of the rig upgrade requirements, casing design, completion design, and simultaneous operations strategy. It will provide a useful guide for drilling staff involved in planning and execution of a subsea development.

Introduction
The Pompano field is located 24 miles southeast of the Mississippi River Delta and comprises 5 Gulf of Mexico Outer Continental Shelf lease blocks. It is being developed by BP Exploration Inc. and its partner Kerr McGee Corporation with a conventional 40 slot platform and a 10 slot subsea production template/manifold. The platform was installed during 1994, in the southeast corner of Viosca Knoll Block 989, in a water depth of 1290 ft. The subsea production/manifold was installed during 1995 in Mississippi Canyon Block 28, about 4.5 miles southeast of the platform, in a water depth of 1865 ft.
The reservoir is located at a true vertical depth of approximately 10,500 ft. Initial bottom hole pressure is about 6,700 psi which equates to a maximum shut-in wellhead pressure of about 4,600 psi, Bottom hole temperature is about 200°F.
BP Exploration had a unique set of problems to solve in exploiting the Miocene reserves of the Pompano field locatedin Mississippi Canyon 28 and 72.Deepwater drillingBlack oil with a high cloud pointUnconsolidated sands.
This paper presents the technical highlights of the well and completion design, necessary rig upgrades required to install the completion and Tlrough Flowline (TFL) trees in 1865 ft water depth, key parts of the TFL completion installation procedure, and the simultaneous operations strategy in order to maximise oil production during a continuous drilling program.
First oil was achieved from the platform in the fourth quarter 1994, and is expected from the subsea in the first quarter 1996. This paper should be read in conjunction with 1996 OTC papers 8205 and 8209 (Refs, 1 and 2) in order to gain a full understanding of the complexity of the Pompano subsea development scheme.

Well Design
Rig Upgrade. A rig was selected that would be able to perform completion operations in 1865 ft water depth and handle 55 ton subsea trees. However, there were a number of additional modifications which needed to be carried out in order to perform the requird operations on this development. These consisted of:-
Mooring. Additional 3.25 in anchor chain was added to allow the mooring system to meet the BP Exploration design criteria of being able to handle a 15 year return period hurricane with one mooring line broken.
Oman India Pipeline: An Operational Repair Strategy Based on a Rational Assessment of Risk
Authors: German Philip 
Published: October 2008

Abstract
This paper describes the development of a repair strategy for the operational phase of the Oman India Pipeline based upon the probability and consequences of a pipeline failure. Risk analyses and cost benefit analyses performed provide guidance on the level of deepwater repair development effort appropriate for the Ornan India Pipeline project and identifies critical mm toward which more intense development effort should directed.
The risk analysis results indicate that the likelihood of a failure of the Oman India Pipeline during its 40-year life is low, Furthermore, the probability of operational failure of the pipeline in deepwater regions is extremely low, the major proportion of operational failure risk being associated with the shallow water regions.

Introduction
The Oman India Pipeline (OIP) will transport natural gas approximately 1100 km from Oman to India under the Arabian Sea at water depths to 3540 meters. The majority of the Oman India Pipeline route is not diver accessible, Diverless pipeline repair systems are currently under development by the offshore industry at a modest pace, but a diverless pipeline repair has not been performed to date; although a number of pipelines are currently in operation in water depths beyond diver reach. Hydrate formation resulting from pipeline failure and subsequent water ingress is the subject of a separate program of investigation. This programmes includes physical testing and mathematical modeling to gain thorough understanding dehydrate morphology and confirm the proposed engineering solutions.

Risk Analysis
Overview. As part of the comprehensive risk analysis program undertaken for the Oman India Pipeline project, an operational risk assessment of the subsea pipeline was performed to determine pipeline failure probability subsequent to successful installation and start-up, during its 40-yw design life. Expected hazards which may threaten the subsea pipeline during operation and the of failure initiating events resulting from those hazards were identified. Hazards evrduated include those that stem from natural phenomena such as earthquakes, subsea landslides and ocean dynamics; third-party events such as vessel accidents and anchor dragging incidents, sabotage and military action and processes such as internal and external corrosion. The operational risk analysis was performed for discrete regions or zones along the proposed pipeline route permitting characterization of the various zones based on unique features or common susceptibility to hazards. The overall pipeline operational reliability was then obtained by integration of the reds for each zone.

Zone Delineation.
The subsea portion of the pipeline was segregated into sixteen zones along the planned route across the Arabian Sea and the hazard probabilities for were zones were ranked and quantified.
Subgouge deformations and the security of Arctic marine pipelines
Authors: Woodworth-Lynes Christopher , Nixon Derick , Geotech Nixon , Phillips Ryan , Palmer Andrew 
Published: October 2008

Abstract
Pipeline engineers have been concerned to protect underwater pipelines from icc masses, which can gouge 5 m and more below mudline. Their initial concern focused on a requirernent 10 avoid contact between the icc and the pipeline: if the pipeline was trenched below the maximum gouging depth below mudline, the pipeline was supposed to be safe.
It is now clear that this is not so. Very Iarge deformations occur in the soil below a gouge, so that a pipeline can he damaged even if' it is too deep for the icc to reach it. This has been demonstrated by the PRISE joint-industry project, which combines centrifuge modelling; analytical and finite element studies of gouging processes and pipeline response; and field studies of relic gouges. The results give some guidance on the necessary depth of burial, which is significantly greater than the maximum gouge depth, but this is a premilinary Study and further verification and research are neccessary.

Introduction
Large areas of the seabed in the Arctic arc heavily gouged by grounded sea icc pressure ridges. Icc gouges arc most frequent in shallow water, but extend to water depths beyond .S0 m, much further in areas where icebergs occur. Gouge may be 5 m or more deep and 50 m or more wide. Respective mapping confirms that gouging is a contemporary rather than a relic phenomenon. Straight forward calculations show that enough driving force is available the observed gouges, anti [hat icc keels can be strong enough 10 do so although a degree of smoothing occurs when a keep first contact the bottom, particularly if it is an weak(unconsolidated first-year keel).
Gouging has serious implications for subsea pipelines, An icc mass Iarge enough and strong enough 10 cut a deep gouge can damage a pipeline severely if comes into contact. A rough of the gouge force can readily be made', and can be confirmed by the modeling described Iater. A Iarge gouge requires an icc force of the order of 200 MN tonnes. This is 1000 times the pullover forces which are known not 10 damage properly-designed large North Sea pipelines when they arc struck by trawlgear. on the other hand, it is lot) times Iarger than the forces occasionally accidentally applied by anchors, which are known to cause extensive damage. While in principle it is practicable to design a protective system to withstand these huge forces, if demands a radical change in design, and the cost of the productive structure would be extremely high. until relatively recently, it was thought that a pipeline would be safe if it were buried sufficiently deep below the seafloor for icc to cross the pipeline without it.
Subsea Manifolds Optimization - The combination of Mature and New Technologies
Authors: Paulo C.A.S. 
Published: October 2008

Abstract
Subsea equipments can be considered nowadays a mature option for offshore field developments. In Brazil, since the first oil in Campos Basin, different concepts ranging from one atmosphere chambers to deepwater guidelineless x-mas trees, have been tested, contributing for this development. @The experience acquired during these years makes it possible to combine the proven systems to the new technologies being developed, for the design of subsea manifolds The main target is more etllciency and cost reduction. When choosing a manifold concept. a usual rule is applicable: the simpler the better.
The maturity, confidence and reliability obtained, allow the usage of resident hydraulically actuated valves, simplifying considerably the manifold arrangement. Other contributions come from: the reduction of piping bend radius allowed by the new pigs; the increased reliability of subsea instrumentation and chokes, allowing elimination of the gas-lift-test flowline, and the development of the direct vertical connection, that turns subsea tie-ins very fast and easy operations. Combining all that with the new technology of multiphase meter (to eliminate the test flowline and even the test separator on the platform), we can achieve a cost effective solution.
This paper describes the possibilities of simplifying the subsea manifolds and presents a comparison of different designs. The usage of mature technology combined with the new developments, can help the industry to make deep water developments profitable, worldwide.

Introduction
Aiming cost reduction, efficiency and reliable solutions for future deepwater developments, PETROBRAS has carried out a study for comparison of different manifold concepts to identify the potential more attractive ones. For a more realistic analysis, [he manifold was not studied as an isolated item, but, using a system approach, all the subsea components were considered trees - flowlines - connections - controls - manifold - export lines and umbilicals. @In this comparative study, mature technologies of subsea valves, chokes, controls and instrumentation were combined with the new developments of flowline connection systems and multiphase meters to achieve cost effective alternatives.

Base Case and Technical Parameters Set-Up
The base case used for this comparative work was a system composed of 8 subsea wells that produce crude oil (3000 BOPD each) during the life time of 20 years, using gas-lift as the artificial lift method. The production is commingled in a diverless guidelineless subsea manifold, located 400 m (1,312ft) away from the wellheads. The export lines (production outlet and lift gas inlet) are connected through flexible lines to the floating process unit 3.2 km (2 miles) away from the manifold, Flexible lines are also used for the subsea trees to manifoId connections. Electro-hydraulic multiplexed control system is considered.
Shasta/Mustique Subsea Equipment Platform Interface and Operability
Authors: Jefferies Andrew T. , Loegering Cory , Steib Don , Schlater Don 
Published: October 2008

SUMMARY
The economic benefits of all inclusive systems engineering approach is now recognized in the offshore industry. Nowhere is this more evident than in the area of deepwater subsea tiebacks to existing facilities. This type of development requires effectivemanagement of the interfaces between personnel on the existing facility and the new project team, the interfaces between the new subsea facilities and the existing platform, and the interface of the new operating procedures with the existing platform daily routine.
A second factor in tie economic viability of many of these projects is the need to minimize operating costs by avoiding the need fm subsea .system repair intervention, An operability analysis focusing on the subsea system and platform interface engineering was used on the Hardy projects to address the concern with the potential for interventions, With minimum operating costs as a primary goal, Hardy encouraged participation from both host platform operating groups from the outset of both projects. This cooperation was critical since both projects were planned to mow than double the throughput for both host platforms without adding platform operating personal. The approach of operator involvement also ensured a safe, reliable, and economic transition between the installation and operating phases of the developments.

INTRODUCTION
This paper describes the operability and interface management effort on the SHASTA and MUSTIQUE developments in [he Gulf of Mexico. Hardy's project management approach was apply 10 both developments, however (his paper focuses on the SHASTA development specifically for the installation and operation phase.
The SHASTA field is located in Green Canyon block 136 in approximately 1000ft of water. Hardy Oil & Gas USA inc. was the development opera[or with responsibility for the design, drilling. and installation cycles of the project. Texaco Exploration & Production INC (TEPI) took over as operator of all facilities on production start up. Equity ownership of the field is 50% TEPI, 25% Hardy, and 25% Samedan.
Subsea wells produce gas and condensate through Iwo export flowlines to the Green Canyon block 6 Texaco platform in 612 tl of water. The # 6 well is located in 860 ft of water while the # 7 well is in I(M2 R. The two wells are located 1-1/2 miles apart with the closest well (#6) being 9-1/2 miles from the platform.
The SHASTA subsea wells are controlled from the platform using a multiplexed electro-hydraulic control system. The production facilities added to the platform specifically for S1IASTA have a throughput capacity of 60MMSCFD and include dedicated provisions for flowline pigging and continuous methanol and corrosion inhibitor inject ion. Figure I illustrates the overall field arrangement.
Horizontal Subsea Trees for the Shasta Development:An Operators Perspective
Authors: Lorimer David 
Published: October 2008

Abstract
The Shasta project was managed by Hardy Oil and Gas and the operation handed over to Texaco after first production in November 1995. Weekly team meetings were held from May 199-t to October 1995. These meetings covered the Engineering and Construction phases of the project. Hardy created a unique project team environment which provided an open forum for group discussion. The Shasta subsea team consisted of a Hardy team leader, a Texaco engineer, a Texaco production supervisor and representatives from contractors and manufacturers. Team members were chosen on a partnering basis and not via a formal bidding process. It was decided that a Horizontal tree system should be used for the project (reference Figure 1). This paper describes why and how this decision was made, how the system was put together and how it has worked to date, The Shasta tree is an cmbodiment of team contributions to improvements in the following areas;SafetyReliabilityControls interfaceEase of installationEase of interventionEnvironmental protectionSeal designWireline plug designSystcrn integrationOperability

Introduction
The Shasta field development consists of two subsea wells tied back to Texaco's Green Canyon 6 platform, ?Kilauea'. The offset to the first well is approximately nine miles with an additional mile and a half to the second well, Water depths are 84(M and 104t)ft respectively, The wells arc electrohydraulically controlled by a multiplexed umbilical tied into the G.C. 6 platform Control of the wells is also relayed to the Texaco New Orleans office via the Texaco Stormac SCADA system which allows production to continue in the event of Hurricane evacuation of G.C. 6.
An environment of partnership, team-work and open mindedness on the part of the oil companies and the subsea contractors was essential to the success of the project. All project team members demonstrated a willingness to adopt common goals and strive to overcome traditional technical, logistical and commercial obstacles in new ways. Each contributing team member strove to break new ground and prove their abilities to meet the needs of an ever more demanding subsea environment. The result of this open team approach was the synergy of various abilities, levels of experience and expertise to develop a cost effective subsea production system. Ease of installation and operational flexibility were major considerations during the design stages.

Why a Horizontal Tree?
In order to ensure that the appropriate subsea tree configuration was selected for Shasta, some three months were spent discussing various designs with a number of subsea wellhead manufacturers. The recommendation to use a horizontal tree was made in July 1995, and a thorough project team and partner review was conducted, An extensive Hazop was then conducted to establish operational viability.
Smedvig Production Unit 380- A New Concept
Authors: Nergaard Arnfinn , Lenning Ketil , Levett Chris 
Published: October 2008

Abstract
This paper describes the development of the Smedvig Production Unit (SPU) 380, a new FPSO (Floating Production, Storage and Offloading) concept.
The paper outlines how a market analysis was combined with a business strategy to arrive at a certain set of design parameters and capacities.
With this as input the project team prepared an Outline Specification for a fully integrated production vessel. The Outline specification further termed the input for the Basic Engineering work. Within a time frame of 13 months the project was brought from an idea to the actual ordering of the first SPU 380.

Introduction
The industry is presently witnessing a remarkable boost in the interest for Mobile Production Systems. Mobile Production Systems are either monohull FPSOS (Floating Production Storage and Offloading), semisubmersible FPVS (Floating Production Vessels) or JUPVS (Jack-up Production Vessels).
The increased interest for FPSOS was particularly seen in 1994 when a number of vessels was ordered by oil companies and contractors. Through 1993 and 1994 several designs were developed of which a certain number of purposebuih FPSOS are now about to be realized for start-up of operations in 1996 and I997.
One of the concept designs that was developed during this period was the Smedvig Production Unit (SPU) 380, a medium size FPSO capable of storing 380,000 bbls of crude oil and with a nominal production capacity of 50,000 bbls of oil per day. Ref.
Fig. 1- SPU 380 Artistic Impression.
This paper describes tbe 13-month development of the SPU 380, starting in March of 1993 and ending in April of 1994 when the first SPU 380 was ordered from Far East Livingston Shipbuilding in Singapore.

Market Analysis -1 month
The FPSO as a concept has generally developed from the need to find viable solutions for development of the smaller fields, say for recoverable reserves of less than 50 mill. bbls.
Over the last 15 to 20 years the industry has seen a number of tanker conversions adapted to meet the criteria of small fields. In general the project model has been for oil companies to buy a second-hand tanker, convert it and produce the field for a certain number of years. The average production life time has been in the range of 3 to 7 years. Although some of the vessels have been redeployed for a second production application they have normally been planned for one specific field application only.
Over the last 10 years contractors have seen this as aninteresting business opportunity. One vessel might be designed with sufficient flexibility to serve a number of the smaller fields, The business strategy is then for the contractor to own and operate the vessels and thus offer a service rather than the facilities as such.
FPSO's Fulfilling Shelf Requirements by the Maritime Approach
Authors: Baunan T. 
Published: October 2008

Abstract
Purpose-built FPSOS have at present gained a position by operators as a viable and technically fully acceptable solution compared with the cautious attitude experienced only a few years ago.
During these years we have also seen that the majority of the FPSO's have been contracted to traditional shipbuilders for construction.
The transition from the typical ?fixed offshore platform' environment to the ?floating offshore installation' environment of marine builders (i.e. shipyards) has posed quite a few challenges to all involved parties.
The role of offshore legislators and their adaptation to the new players. i.e. yards, vendors, ship owners as well as Marine Administrations and Classification Societies have and will continue [o undergo changes to adjust to the offshore industry which extends way beyond the mobile drilling unit practice.
However, the tradition and the practical approach of the maritime industry can be satisfactory mated with fixed offshore practice contingent that the two cultures are willing to appreciate the best of the other. Among the challenges to be taken in this respect, the most important task is for the marine industry to take and exercise a dedicated ownership of the philosophy and principles of risk based design and implement it throughout all stages of an offshore project.

1. INTRODUCTION
FPSO's, or Floating Production. Storage and Offloading Vessels, are by no means a new concept nor unproved, but the North Sea Continental Shelves have not been folly aquatined with these until the recent years.
Tankers for oil and a few column stabilised units have been converted into FPSO/ FSO / FPU'S for operation in Brazilian and Asian waters the last two decades and proven to suit the demands set forward by the operators, The UK Continental Shelf (UKCS) has also seen an increased volume of converted tonnage enter into FPSO service in harsh environments, but it was not before the entrance of the Petrojari 1, a purpose built new production, storage and offloading ship. that FPSO's attracted serious attention from major Norwegian operators. However, it took another two FPSO new buildings initiated on a speculative basis by Norwegian ship owners before the concept of FPSO's gained the present dominant position in the North Sea region.
In regions outside the North Sea, converted tankers or semi's are still the preferred option, although a few new built FPSO's have entered into service in Asian and Australian waters.
The transition from the typical ?fixed offshore platform' environment with a network of well established offshore fabricators, engineering companies and vendors 10 the ?floating offshore installation' environment comprising of marine builders (e.g. shipyards) with their network. has posed quite a few challenges.