bluuebunny/crossref_metadata_2025_split huggingface dataset:
Neptune Project: Spar Hull and Mooring System Design and Fabrication
Authors: Kuuri J. , Lehtinen T. , Miettinen J. 
Published: October 2008

Abstract
The Spar hull applied on the Neptune Project is 72 ft in diameter and 705 ft in length. It provides the buoyancy for the support ofthe production 'facilities and well work capability for the production and processing of the hydrocarbons. in Viosca Knoll 826 unit. The hull was designed and fabricated in Pori, Finland. This paper describes the design and fabrication techniques that were utilized to construct and handle the large hull sections. The assembly and inspection processes will be addressed. Due to the large diameter and length of the hull, special transportationtechniques were required. The hull was assembled in two large main sections and then dry transported to the Gulf of Mexico forfinal assembly. Methods used in alignment, and welding these large sections, while floating, will be presented. The special mooring system consists of a six leg taut mooring system composed of wire rope and chain. This marks first use of studless chain for a fixed mooring system in the Gulf of Mexico.

Introduction
The Neptune Spar hull was successfully engineered and built in Finland to two main sections, transported to the Gulf of Mexico for joining, joined floating in water, and the hull was then delivered to Oryx Energy Company (Oryx) floating horizontally at quay side after a 19.5 months contract period. The project was executed on the schedule originally set in an EPC contractbetween Aker Rauma Offshore (ARO) and Oryx as a part of the Neptune field development1.
The Neptune Spar project was a pilot milestone for the long cooperation between Deep Oil Technology (DOT), ARO and J. Ray McDermott (JRM) for developing the Spar type floating production platform. The Neptune project proved the new Spar hull construction techniques and feasibility of a taut mooring system for deep water developments in the Gulf of Mexico (GOM).

Project Execution Outline .
The technical basis for the Neptune hull and mooring contract was built in a preliminary engineering effort mobilized by Oryxafter initial concept feasibility studies. The preliminary engineering phase started in January 1994 and lasted until October 1994. The work included definition of the main dimensions and characteristics for the hull, topsides, and mooring system. ARO was responsible for the development of the hull and mooringspecifications, hull main scantling plans, hull marine system diagrams and arrangements. The best construction method was developed together with the Mantyluoto Works (MW) construction yard. Documentation for the hull structures was submitted to ABS for review and major elements of the hull were approved by ABS in late 1994.
Based on the preliminary engineering work a firm bid was submitted for the hull and mooring system covering project management, engineering, procurement and construction. Oryx decided to go ahead and on 2 February, 1995 issued ARO a lump sum contract for delivery of the Spar hull and the mooring system components excluding the anchor piles (Fig. 1).
Conceptual design work and analysis was carried out by DOT.
Advances In Artificial Lift And Boosting Systems For Subsea Completion
Authors: Camargo R.M.T. , Alves I.N. , Prado M.G. 
Published: October 2008

Abstract
Most of Brazilian oil and gas reserves are located in offshore deep waters. In this scenario, high well productivity is essential. Artificial lift will certainly play an important role in the exploitation of those deep water fields.
This paper describes the most important artificial lift methods, their main characteristics and application niches. It also shows what Petrobras is currently doing in order to make them available for subsea use.
The following methods are analysed:gas lift;electrical submersible pump;hydraulic jet pump;progressing cavity pump;multiphase pump;subsea separation system.

Introduction
Petrobras is the world leader in subsea completion. For subsea application only gas lift has been widely used as artificial lift method, due to its intrinsic similarity with onshore's gas lift method. This similarity comes from the fact that it is driven by a power fluid using roughly the same components for both onshore and subsea application. For this reason, gas lift is today seen as the subsea conventional artificial lift method. Sometimes, gas lift may not be the best method to fit specific field's requirements. This happens, for instance, when there are long distances between well heads and platforms, and the gas injected, even though helping the flow in the vertical sections (well and riser), increases pressure drops in the horizontal section (flow line). Additionally, this method demands compressors and an increase of gas facilities to handle the extra recycling gas, with consequent drawbacks on platform weight and area requirements, which have a high impact on offshore installations costs. Of course, there are other limitations for the gas lift method, but this will be addressed later.
As a major oil company, with large offshore hydrocarbon reserves and more than 60% of nowadays' total production coming from offshore wells, Pepobras is currently feeling the need to adapt some artificial lift techniques, in order to make them available for subsea use as an alternative to the conventional gas lift method. Petrobras believes that each of these options may find some fields with adequate set of characteristics that make them the proper choice for their exploitation.
This paper describes the major characteristics of each method currently under development for offshore use (focusing on subsea applications), the expected characteristics of theirs application niche (advantages and disadvantages), the probable major problems for their extension to subsea use and their current development stage at Petrobras.

Artificial Lift Methods Description
In this item it will be discussed the main characteristics of each method, as well as the difficulties to adapt them to subsea use. What Petrobras is currently doing and planning to do for each method will also be discussed.
Joint Agency Cooperation to Ensure Safety and Protection of the Environment Through Pipeline Inspections
Authors: Bell Theresa P. , Hoffman Catherine M. , Hart James B. 
Published: October 2008

Abstract
The paper describes the use of automatic welding and ultrasonic weld inspection for the deepwater J-Lay of the 18-inch oil and 14-inch gas export pipelines from the MARS Tension Leg Platform (TLP) in the Gulf of Mexico. While automatic welding has seen frequent use on offshore pipelines, its use on deepwater J-Lay was a first, and a significant development effort was undertaken to ensure success during offshore pipelay. To maximize the probability of detecting significant weld defects in these deepwater pipelines, especially those defects with significant through-wall height, Shell specified use of automated Ultrasonic Inspection (UT). This type of inspection can be used to quickly and accurately locate and sue the through-wall dimensions of a defect. These features, in combination with the high toughness of the automatic welds, made it possible to use the Alternative (i.e. Fitness for Purpose) Acceptance Criteria of the Appendix to API 1104, instead of the workmanship criteria of Section 6 of API 1104. As such, a good balance was achieved between, on the one hand minimizing the overall repair rate by not having to repair indications that were not harmful to the weld, an4 on the other hand, maximizing the probability of finding and suing significant weld defects. This first time use of automated UT and application of fitness for purpose weld acceptance criteria on an offshore pipeline project in the Gulf of Mexico goes a long way towards validating the approach as a suitable and cost effective inspection method.

Introduction
The MARS Tension Leg Platform (TLP), a 72%28% joint venture between Shell Offshore, Inc. and BP Exploration, is located in Garden Banks Block 864 in 2940 ft water depth. The two export pipelines, a 14-inch gas pipeline, and an 18- inch oil pipeline were to be installed by J-Lay, using the same J-Lay equipment and lay vessel (the dynamically positioned Derrick Barge DB 50) as used previously to install the 12- inch export pipelines to Shell's Auger TLP'. Dunng J-Lay 165-ft-long pre-fabricated quadruple joints are brought onboard in large storage bins. The quadruple joint is upended in the J-Lay tower and welded in a single station. While on the Auger Project acceptable cycle times were achieved using manual welding (SMAW), the larger pipe diameter and wall thickness on the MARS project warranted an investigation of using automatic gas metal arc welding (GMAW) to obtain much faster joint cycle times than could be achieved using SMAW. The pipelay contractor J Ray Mc Dermott and Shell had negotiated a risk sharing agreement, where both would pay for the incremental cost of automatic welding and UT, but also would share savings resulting from a faster lay rate.
Development of Cyrogenic Marine (In-Water) LPG Export Hose Escravos Gas Project
Authors: Woehleke S.P. , Jones H.T. , Zaffagnini M.P. , Gallant G. 
Published: October 2008

Abstract
A cryogenic marine hose has been developed for exporting LPG at minus 43 degrees C as part of the Chevron Nigeria Escravos Gas Project for Chevron Nigeria Ltd. and the Nigerian National Petroleum Company. The LPG will be stored in a permanently moored floating storage and offloading (FSO) system. Environmental conditions require mooring the export tanker in tandem with the FSO. To transfer the LPG from FSO to export tanker, a program was initiated to develop a floating marine cargo hose suitable for this application. This will be the first application of such.
The development program was conducted in three phases, 1) Engineering, 2) Prototype Hose Construction, and 3) Prototype Hose Testing. The development program was designed to establish confidence in deploying the hose; the test program addressed a wide range of conditions. The development program was successfully completed and manufacture is underway for field deployment in early 1997.

Introduction
Chevron Nigeria Ltd. (CNL) produces approximately 400,000 bbl of oil per day, most of it coming from the Escravos area, offshore Nigeria. Along with the oil is a large quantity of associated gas which is flared. To reduce flaring and to recover the gas and condensates, Phase 1 of the Escravos Gas Project (EGP) was initiated by the joint venture partners, Nigerian National Petroleum Co. (NNPC 60%) and CNL (40%).
Figure 1 depicts the field layout and the EGP phase 1 Development Plan. The EGP consists of three major elements:New Gas Gathering, Compression and Personnel Platforms.New On-shore Gas Processing and Extraction Plant.New LPG Floating Storage and Offloading vessel (FSO) and a Dedicated Shuttle Tanker.
Associated gas from the Okan and Mefa fields, two of the many in the Escravos area, is recover& by the new gas gathering and compression platform. The gas is pumped to the onshore gas processing plant where the recovered gas is processed to produce condensates (which are blended with crude oil for export), natural gas (piped for domestic use in Nigeria) and liquifiedpetroleum gas (LPG, which is pumped offshore to the FSO for refrigeration, storage and export).
The subject of this paper is the program undertaken to develop marine (in-water) LPG hose for transferring the LPG at approximately minus 43 degrees C from the FSO to the shuttle tanker for export to market.

Reasoning for Embarking on the Hose Development Program
During the project definition and conceptual design stage, several configurations were evaluated for storing and exporting the LPG. The configurations evaluated included a deepwater harbor with export terminal and offshore storage and export via an FSO. The offshore storage and export option was selected as the optimal solution.
Development Of A Gas Handling Hydraulic Submersible Pump And Planning A Field Trial, Captain Field
Authors: Cohen D.J. , Dallas J. , Knight F.I. , Woerheide E.A. 
Published: October 2008

Abstract
There are limitations to the amount of free gas that can be handled by high volume downhole pump systems. A new pump design employing axial flow impellers coupled with high speed downhole turbine drive has been developed, and is the first true downhole multiphase pump. This paper describes the staged research and development program leading to the first field trial installation in the Captain Field, in the North Sea. Development and design requirements are reviewed, with the results from laboratory testing in water and nitrogen followed by full scale loop testing in multiphase fluid, including crude, methane and brine. Test configuration is described, and key performance results reviewed. Special testing defined the nature of fluids and rheology related to high rotational speed pumping of viscous crude and brine mixtures in pumps and pipelines.
Following successful laboratory scale testing, design considerations are reviewed for its application in a field trial. Completion design includes provision for open loop flow and access below the pump assembly for coiled tubing intervention. New downhole monitoring systems employ pump and turbine monitors along with pump flow and reservoir evaluation monitoring. The design results in extended range of pump operability, improved reliability, and improved control and reservoir management.

Introduction
As technology improves in horizontal drilling, completion practices, and subsea equipment, the need for high volume downhole pumping systems has increased. Small accumulations or thin oil zones, previously considered marginal, can be exploited economically. But in some applications, pumping systems needed higher gas handling capability because maximizing recovery from individual wells requires larger pressure drawdown. Additionally, horizontal wells located at the top of the productive intervals can encounter free gas caps.
Development of a downhole pumping system that could operate successfully in a gassy environment (higher than 30% gas void fraction), and deliver high reliability was key to exploiting new reserves. This technology could be applied within many major oil compani's existing asset portfolio, such as the Gulf of Mexico or West of Shetlands deepwater environments, and elsewhere in the North Sea. One of the assets that could benefit from this technology is the Captain Field. Although the main area of the field is being developed with Electrical Submersible Pumps (ESP), an isolated gas cap was identified in the eastern section of the field that would limit the reliability of ESP systems, and would limit the withdrawal rate. The field has 19 degree API crude oil, with 88 centipoise (CP) viscosity at reservoir pressure of 1300 psi and 87 deg F.
Wireline Well Tractor: Case Histories
Authors: Hallundbæk Jørgen , Østvang Knut , Haukvik John , Butler P. , Skeie Terje 
Published: October 2008

Abstract
The wireline Well Tractor has in the North Sea area completed various wireline jobs in horizontal and extended reach deviated wells. The electric driven Well Tractor has made it possible to perform wireline operations in horizontal and deviated wells such as PLT jobs with surface read out, running of perforation guns, running of specialized tools, setting and pulling of plugs etc. Since March 1996 the Well Tractor has run numerous jobs on Statoils platforms in the North Sea and also jobs for other major oil companies in the North Sea area and North America. This paper describes the implementation of the Well Tractor technology. Logging, plug setting, perforating operations and fishing in wells with a horizontal section of more than 1600 meters are included in the case histories.

Introduction
The number of horizontal and extended reach wells worldwide is dramatically increasing. It is possible to drill and complete ERD, long horizontal and designer wells with no greater difficulty. However, when a requirement for intervention in these type of wells occurs and in particular for live well intervention, coiled tubing or snubbing operations have up to now been the only options. In many cases and particularly in wells with high well head pressure coiled tubing and snubbing operations are impractical and involve a large amount of costly equipment, personnel and rig time. Logistical problems, in particular for coiled tubing operations are evident, especially for ERD type wells as the coiled tubing reel weight often exceeds the platform crane capacity.
The costs for these horizontal and deviated well intervention operations with coiled tubing or snubbing are excessive and in many cases operations such as production logging is simply not performed because of the costs involved.

Development Phase
Statoil has for the past three years focused on a strategy for reducing intervention costs. As a consequence of this Statoil decided to support and play an active role in the development, testing and implementation of a downhole tractor. Statoil as the head sponsor and Maritime Well Service as the co participating service company supported the development and manufacturing company Welltec. The co-operation and joint efforts of the three companies is the obvious reason for the success of the wireline Well Tractor project.
Economical analyses performed in Statoil have revealed considerable cost savings when utilizing wireline tractors for electric line type operations vs. coiled tubing for the same type of operations. Further, it is expected that the market for production logging in ERD- and horizontal wells will increase due to the reduced intervention costs.
Development, Testing, and Field Case Histories of Multilateral Well Completion Systems
Authors: Longbottom J.R. , Dale Dana , Bruha Scott , Waddell Kevin 
Published: October 2008

Abstract
Multilateral oil and gas well concepts have been in existence since the early 1900's, but advances in directional and horizontal drilling have recently made this reservoir development approach more feasible. Although numerous multilateral wells have been drilled, particularly in the Austin Chalk, until now completion methods have been limited in providing features to manage borehole stability, flow control, and well maintenance.
This paper will discuss several examples of the advances in drilling technology that have made these multilateral well development strategies possible. Information will also be provided on several simple multilateral well completion techniques as well as a multilateral system that will 1) mechanically connect the lateral liner to the parent casing, 2) allow through tubing re-entry access to selected laterals, and 3) seal the junction between the lateral and parent bore so that flow control capability can be maintained. In the latest system developed, the hole size of the lateral has been maximized in comparison to the parent wellbore casing, and full bore access to the lateral liner drift ID without restriction has been provided. Information will be presented concerning the project methods undertaken to develop this system, the bench tests that were performed for the components of the system and results of the full scale system test conducted. An "integrated development" approach with a multidisciplinarydesign team and direct producing company involvement was used in the development of the full featured multilateral completion system and proved to be an instrumental factor in the achievement of its success. In addition to information concerning application of multi-lateral completion techniques to new completions, the concept, as it has recently been applied toa recompletion, will also be discussed.
Case histories of the completion experiences of two wells in which the system has been successfully implemented as well as several earlier successful completions using other systems will be presented. In addition, details will be provided concerning the case history in which the technology was employed in a mature field. Experiences to date have shown that multilateral technology can provide technical and economic feasibility for both new installations and recompletions.

Introduction
Many enhancements have recently been made to multilateral completion systems, not only as a result of advances in technology but also because of changes in developmental concepts that have been instrumental in achieving many of the system successes. A primary factor in the increased interest in multilateral completion technology has been its enhancing impact on the economics of field development.
Steady-state and Transient Thermal Performance of Subsea Hardware
Authors: Zabaras George J. , Zhang Jianfeng 
Published: October 2008

Abstract
The thermal performance of subsea hardware is of ultimate importance to the economic development and reliable operation of deepwater subsea oil and gas systems due to the potential for hydrate formation. Results of numerical calculations are presented on the thermal performance of subsea equipment such as wellheads, tubing and flowline jumpers and flowline field joints. In contrast to previous published studies on the thermal performance of insulated subsea wellbores and flowlines, the currenr. study addresses the thermal performance of the subsea equipment that can provide weak thermal links for the subsea system.
While subsea insulated flowlines can eliminate or reduce the risk of hydrate formation during steady-state production, they may not provide sufficient cooldown time before hydrates are formed during an emergency shutdown. Subsea wellheads, pipe field joints, manifold and flowline tubing jumpers are very difficult to insulate effectively. As a result, these pieces of equipment exhibit faster cooldown to hydrate formation temperature than either the wellbore or the flowline.
A two-dimensional general purpose finite-element partial differential equation solver was utilized to analyze the steady state and transient thermal behavior at different cross-sections of the subsea tree. In contrast to the intuitive common belief that a subsea tree cool down time to hydrate formation temperature is of the order of several hours. a cool down time less than two hours was determined after a system shutdown. Steady-state analysis of a flowline field jo nt indicates that the joint degrades the flowline thermal performance causing up to a 20%) increase in the flowline overall heat transfer coefficient. To our knowledge. such results have not yet been presented in the literature.

Introduction
Significant opportunities exist to employ subsea methods in the development of oil and gas fields in deepwater environments. Subsea methods are proving to be not only safe and reliable but often the most cost effective development option.
Subsea system design is driven by many factors such as produced fluid phase behavior and multiphase flow characteristics in flowlines and wellbores, as well as our ability to reliably predict the fluid behavior and the equipment performance over the range of conditions to be encountered during the produce life of the field. While all these factors are very important, the behavior of the reservoir fluids is a key element in the successful design and operation of a subsea system.
The potential for hydrate formation in a produced reservoir stream is perhaps the greatest challenge in any deepwater development in the Gulf of Mexico and elsewhere. Significant design effort and cost for subsea systems is directed toward mitigating the risk of plugging the system with hydrates1 and paraffins/ asphaltenes2,3.