bluuebunny/crossref_metadata_2025_split huggingface dataset:
Inspection and Evaluation of Offshore Pipelines in the Bay of Campeche
Authors: Valdez V.M. , Bayazitoglu Y.O. , Weiss R.T. , Valle O.L. , Hernández T. 
Published: October 2008

Abstract
In October 1995 Hurricane Roxanne damaged offshore installations in the Bay of Campeche. To assess the condition of significant pipelines. a major inspection program involving over 450 km of pipelines was conducted to survey the location of the pipelines and to determine their relationship to the seabed. Lines not fully buried were visually inspected by multiple video cameras. The results of the inspections were presented on charts, data files and video tapes.
These results were utilized along with existing design information to assess the condition of the pipelines and to identify locations where remedial work was needed. The hydrodynamic stability of all exposed pipelines was analyzed to determine the need for pipeline burial. Damage to the pipes, weight coatings and corrosion protection systems was analyzed on a case-by-case basis.
'The paper will review the pipeline inspection objectives, procedures, and results. Evaluation procedures using this information will be described along with a summary of the conclusions of the study.
This is one of the largest and most comprehensive evaluations of existing pipelines ever conducted worldwide and provides a model for future evaluations of aging or damaged pipelines. The improved location and condition information provide a sound basis for appropriate maintenance and operational planning for these lines.

Introduction
When hurricane Roxanne passed through the Bay of Campeche in 1995, the area's petroleum production infrastructure experienced extreme environmental conditions that put the physical integrity of the pipeline systems at risk. Pipeline failures caused by this event had a considerable financial impact. These failures were identified and repaired shortly after the hurricane in most cases.@ After an event like hurricane Roxanne, an assessment of the condition of the pipeline systems that were damaged or of strategic importance was needed. In order to make an assessment, through inspections of selected submarine pipelines and risers were needed in order to obtain detailed information about the condition of the system and to identify damage caused by the hurricane not associated with obvious failures.@ In order to properly evaluate the condition of the facilities it was also necessary to determine if the existing metocean criteria used to design the facilities needed to be revised. To achieve this purpose, a hindcast was needed of the weather and sea state conditions during the passage of hurricane Roxanne. Hindcasts were also needed of other hurricanes and strong storms that have affected the Bay of Campeche. This information could then be used to develop a statistical estimate of the 100-year storm conditions which are commonly used for design and evaluation purposes.
Using data obtained from the special inspections and from the 100-year storm criteria. mathematical models of the pipelines and risers could be prepared and analyses be made to check the stress and stability on each pipeline component.
Captain Horizontal Development Wells: A review of Key Design and Operational Issues
Authors: Tavendale F.M. 
Published: October 2008

Abstract
The Captain field, situated in the U.K. sector of the Central. North Sea, is a shallow heavy oil accumulation contained within massive and unconsolidated sandstone. In order to commercially develop Captain, production wells require to be drilled and completed with up to 6000 ft. of horizontal reservoir section. Key design, planning and operational issues leading to the successful pre-drill and suspension of seven wells are discussed.

Introduction
The Captain field is located in a water depth of 341ft. Hydrocarbons are trapped in two structural closures, the Main and Eastern Closure areas. The contents of this paper pertain to the pre-drilling of development wells in the Main closure area (denoted Area A). Two reservoir intervals are hydrocarbon bearing in the Main closure area; the Lower Cretaceous, Upper and Lower Captain Sands. The reservoirs have the characteristics of high permeability averaging 7 Darcies, high porosity circa 30% and are unconsolidated. Average reservoir depth and temperature are -2900fi. tvdss and 87 degrees F respectively. The oil is viscous and heavy by North Sea standards with oil viscosity at reservoir conditions between 47 and 205 centipoise (cP) and an oil gravity of between 19 and 21 degrees API (Table 1). The fluid properties and offshore environment require innovative horizontal drilling, completion and artificial lift technology for economically successful field development. Development risks were significantly reduced with the successful drilling and 93 day testing of a prototype field development well during 1993 (13122a-10).
The initial development area covering the western sector of the Captain Field comprises a wellhead protection platform (WPP) tied back by a suite of pipelines to a floating production, storage and offloading vessel (FPSO) from which export quality crude is offloaded by shuttle tanker. In order to accelerate field plateau oil rate of 60000 bopd seven wells were predrilled, lined with screens through the reservoir and suspended for future reentry from the WPP. Of the seven wells three are horizontal oil producers to the Upper Captain Sand (UCS), two are horizontal oil producers to the Lower Captain sand (LCS), one is a horizontal water injector to the ucs and one is a high angle water supply well (WSW) to a lower isolated reservoir (Fig 1, Table 2). The main design, planning operational concerns related to the drilling of a typical oil producer are discussed.

Well Design
Casing/Hole Size. Production rate requirements for each well dictated that a in internal diameter be provided in the reservoir section. This defined a minimum hole size of 8.5 in through the reservoir to accomodate pre-packed screens. The hole size was subsequently modified to 8.75 in. The size of Electrical Submersible Pump (ESP) required to deliver 15000 BOPD established the requirement for a minimum casing size of 9-518 in. above the reservoir.
Steel Catenary Riser for a Taut-Leg Moored Semi-submersible Platform
Authors: Franciss R. , Torres A.L.L. , Mourelle M.M. , Pinto F.J.C.P. , Souza L.F.A. 
Published: October 2008

ABSTRACT
Following the tendency of using steel catenary risers (SCR's) for export lines in Campos Basin, PETROBRAS developed a project for installation of two 12" oil export SCR's in the semi-submersible platform P-19, at Marlim Field, in a water depth of 770 meters. The platform will be taut leg anchored with 16 polyester chain lines. The risers will be connected to the portside platform pontoon, in order to minimize the action of the waves directly on the risers and for safety reasons. This paper describes the design, components, specification and installation of the SCR's.

INTRODUCTION
To continue the development of exploration and production of Campos Basin, PETROBRAS will install in 1997, the P-19 platform, a taut leg moored semi-submersible platform located in the Marlim Field, in 770 m of water depth. The production will flow through flexible lines, hanging at the spider deck level. The oil will be exported to a Pipeline End Manifold, using two 12" steel catenary risers (SCR) connected to two 12" pipelines.
This solution was first studied in 1987, when PETROBRAS participated in a IIP' developed by SHELL and, since then, further studies were performed by PETROBRAS, at it's Research Center and at the E&P Department, to develop this technology.
PETROBRAS will install its first SCR, as a prototype, in the P-XVIII Semi-submersible platforms, in 910 m water depth, in 1997. This riser will be monitored during one year and the results will be compared with the design data and with simulations that will be performed with computer programs. Stresses, vibrations due to wave forces and vortex shedding, offsets and platform motions will be measured. Metocean data, including directional waves, currents and wind will be monitored too. This riser will be connected later in the end of 1997 with flexible lines, to the P-26 Platform.

A TAUT LEG PLATFORM
The function of a mooring system is to restrict the lateral motions of the floating structure within specified operational constraints. The overall design parameters are typically in terms of maximum allowable offsets, varying according to the platform operating conditions and the riser requirements, with limitations on maximum mooring line loads and other more specific constraints.
The design loads on the system are generated by wind, waves and currents. The mooring system operates by developing horizontal components at the points of attachment to the floating structure.
The polyester rope taut leg mooring concept allows cost reduction and improves the station keeping performance3. In the taut leg geometry, the platform mooring lines are terminated with suction piles or vertical loaded anchors, as showed in Fig. 1, to develop higher horizontal components, resulting in reduced mooring pattern radius around the platform.
Marlin Deepwater Riser Alternatives Risk Assessment
Authors: Wolford Andrew J. , Penyman Stephen R. , Deegan F. Jonathan , Gosch Stuart  W. , Stahl Bemhard 
Published: October 2008

Abstract
A study was undertaken to determine, for the Marlin deepwater development, the risks and benefits associated with the use of dual casing risers, compared to single casing riser design.
The study involved carrying out and linking 1) Failure Modes and Effects Analysis, 2) Fault Tree Analysis, 3) consequence severity ranking by experts, 4) cost (risk) 1 benefit assessment, 5) decision analysis, and perhaps most importantly, the study led to 6) team building and buy-in.
The results produced in the study were robust and demonstrated a clear preference for the single casing riser alternative.

Introduction
Amoco Production Co. is the designated operator of the Marlin deepwater development, located in the Viosca Knoll area 85 miles ESE of Venice, LA in 3240 feet of water. Key parameters from the Design Basis Document are summarized in Table 1.
The initial development of Marlin will consist of a five well (2 gas / 3 oil) development. In addition, when some of these wells are exhausted, one up hole re-completion and one sidetrack and completion are planned. The initial five wells will be pre-drilled using a MODU and once the platform isinstalled the final completion of these five wells will be undertaken using a workover rig. The subsequent workover and development drilling operations will be carried out using a similar workover rig.
The Marlin design team's conceptual design basis assumed that the wells would be tied back from the seafloor to the surface vessel with dual casing production risers, capable of carrying full shut-in tubing pressure. These risers are essentially dual concentric, redundant risers surrounding the production tubing running from 200 feet below mudline to the surface wellhead. A number of potential hazards during production and workover can prompt a requirement for this level of redundancy in barriers.
The purpose of this study was to determine the risk-benefit associated with the use of dual casing risers, compared to single casing riser design.

System Description
The Marlin riser systems consist of two similar designs of production riser system. The two designs are similar in most aspects except for the second (concentric) riser casing string in the dual riser case.
A system definition and boundaries were developed for the study. The basis for the definition of these system boundaries was the Marlin Field Design Basis Document and the details of the system components provided by the Marlin well systems team members.
The system configuration for the normal production mode is represented in the simplified completion diagrams shown in Fig. 1 for the single and dual riser cases.
The system configuration changes when the system is operating under either a workover or development drilling mode.
lnstallation of DeepStar's Polyester Taut Leg Mooring
Authors: Dove P.G.S. , Fulton T.M. , Devlin P.V. 
Published: October 2008

Abstract
During the summer of 1995, an attempt was made to install DeepStar's single leg polyester Taut Leg Mooring (TLM). Problems were encountered with chafing on one of the polyester rope sections and installation could not be completed on its first attempt. In September 1996, however, the system was successfully installed by Aker Marine Contractors, Inc. (AMC), under contract to DeepStar.
This paper describes the lessons in polyester rope handling and installation learned through the 1995 attempt, and how they were applied to the successfid installation work that took place in 1996. It also describes the TLM and its instrumentation and details the procedures used for the installation work.
The TLM, whch is located about two and one-half miles to the south of Shell's Auger TLP, is now being used as a standby mooring to allow supply vessels servicing the TLP to secure during delays in offloading. The TLM is equipped with special instrumentation that monitors real time tension, buoy heave and a heading sensor that determines buoy rotation. An onboard computer receives and stores the measured data, which is transferred to AMC's offices on a regular basis. The TLM will remain on station until September 1998, at which time it will be recovered by AMC. Three polyester rope section types were included in the TLM: two of a parallel-strand construction and one a multi-strand type. After recovery, 40 ft sections of type will be break tested and compared against new samples that were not installed in the system.
The test marks an important continuation of the development work in deep water moorings being conducted by DeepStar and industry and should allow the large scale use of polyester in TLMs in the Gulf of Mexico by the turn of the century.

Introduction
In recent years much attention has been paid to mooring systems for very deep water drilling and floating production applications. Because of the potential for reducing mooring system costs and limiting vessel excursions, the offshore industry has recently given serious consideration to the use of taut leg mooring systems. Although costs can be reduced for deep water mooring applications (&gt;3,000-4,000 ft) using conventional components in a taut leg system (i.e., steel wire rope and chain and driven or drilled/grouted piles), additional cost savings can be achieved by considering the use of synthetic materials to replace the steel used in mooring ropes and either suction pile anchors or vertically loaded drag embedment anchors (VLAs) to replace piled anchors. For these reasons, polyester taut leg mooring systems have been a focus area for the DeepStar project over the last few years and the reason that DeepStar has embarked on the TLM test program. The test system installation and lessons learned are described in this paper.

Test Objectives
The following objectives were sought by DeepStar in the decision to proceed with the single leg polyester TLM test:
Low Cost Deepwater Hybrid Riser System.
Authors: Hatton S.A. 
Published: October 2008

Abstract
The design and analysis of a cost effective multi flowpath production riser for deep and ultra deep water floating production systems is presented. The design is based on a bundled concept using beach fabrication and installation by near surface tow. The study has been funded by the Deepstar project and addresses water depths between 1300 and 2200m in the Gulf of Mexico. The riser is designed to interface with a semi submersible production vessel but may also be used with an FPSO with minor modifications.
The design approach minimisis the riser steel weight and buoyancy requirements and achieves an optimum dynamic response through an efficient structural design and buoyancy distribution. This maximises riser flexibility and minimises hydrodynamic wave loading.

Introduction
The definition of 'Deep water' changes every year. Operators are currently developing reservoirs in water depths up to 1500m and have drilling campaigns planned for depths beyond 2000m. Production technology for such water depths is likely to center on semi submersible and ship shaped floating production systems which are well established in shallower water depths.
The riser systems, used to transport production fluids between the seabed and vessel, will become an increasingly important aspect in deep water developments. Risers are dynamic systems which operate at high pressures and temperatures often with corrosive fluids. Consequently, risers are technically complex and the materials and methods of manufacture and make them costly. These issues are compounded as water depths increase due to higher loads and lengths involved making riser system selection and optimization even more complex. Deep water developments to date have largely extended shallow water, flexible riser, technology through the development and application of new materials and manufacturing techniques. However, extending a successful shallow water solution to deep water is not necessarily the most economic or technically preferable approach. Whilst in shallow water high pipe flexibility is required to accommodate vessel motions, in deep water stiffer pipe may be considered due to the beneficial effect of water depth on riser system compliancy.
In recent years new riser arrangements have been conceived to meet the challenge of deep water, offering significant commercial and technical advantages over conventional riser systems. These new riser systems utilize steel pipe which has a relatively low cost compared to flexible pipe. The importance of these new riser systems is significant. Commercially, they provide an alternative to the flexible riser but more importantly, in many cases, they provide a technical solution where no feasible solution exists with flexible pipe.
The two most promising riser concepts are the hybrid riser [1,4] and the steel catenary [2,5]. Both concepts can be configured in a number of ways depending on application and even combined as in the case of the Tension Leg Catenary (TLC).
Applied High Pressure Coiled Tubing Technology Solves Resin Sand Control Problems In A Gulf Of Mexico High Pressure Gas Well
Authors: Zimmerman Joe , Sargent Tim , Clawson Greg 
Published: October 2008

Abstract
The current API and ASME design codes on wall thickness selection are too restrictive for the application of high pressure subsea flowlines. At present the codes require flowlines to be designed to wellhead shut-in pressure using Barlow design formula, which is based on first yield, and working stress safety factors established decades ago. Recent advances made in pipe manufacturing, design engineering, and the considerable plasticity of thick walled steel pipe render the current design overly conservative, resulting in severe cost penalties for long distance subsea tiebacks.
The current work describes the application of Burst Limit State Design principles to the design of subsea tiebacks. The paper discusses the limitations of the classical approach and quantifies the uncertainties, risks, and economics of limit state design, based on results obtained from burst pressure test data obtained from various industry sources. It is expected that this work will lead to a review of the existing codes by the regulatory bodies and the recommendation to change current in design practices.
The work will enable deepwater subsea tiebacks to be designed in accordance with limit state principles and safety factors reflecting the current state-of-the-art technology of pipe materials, manufacture, welding, quality control and pipeline design. This will lead to the optimum design of subsea flowlines.
This work is mainly directed towards the large D/T ratios required for high pressure subsea flowlines, and is different from the low D/T ratio work carried out by SUPERB and IS0 working committees in Europe. However, it is intended that this work will complement the work carried out elsewhere, leading to a consistent application of burst pressure design to pipelines and flowlines.

Introduction
DeepStar 3300 Committee commissioned a study to evaluate the feasibility of using the Burst Limit State criteria to design subsea flowlines. The work consisted of:Collection of data from published sources and DeepStar members.Identification of Limit State Design models for Burst Assessment of code compliancePreparation of submissions to API and ASME for code changes
The work presented here is limited to the Phase 1 of the study, and includes a description of the data collected, and the preliminary Limit State Design philosophy under development. Comparative cost data for current design practices, and Limit State Design also given to establish the potential cost savings of using Limit State Design.
Recognition of the uncertainties associated with engineering systems has led to the wide application of the concept of reliability as a basis for structural design. This is evidenced by the move in Europe and North America to develop limit states codes for pipeline design.