bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Operation Of The Multiphase Flow Meters On The Sour Environment Of QTIF Field (Case Study)
Authors: Al-Dossary Faisal Mohammed , Al-Ghamdi Abdulrahman Ahmed 
Published: July 2009

Abstract
Qatif field is the first intelligent field in Saudi Aramco equipped with measurement, communication, control and software enabling semi real-time and automated asset management and field rate optimization. Qatif is fully automated with remote controls, due to its complex reservoir characteristics and fluids with high H2S concentration. Difficulties were experienced with one of the main intelligent components of the surveillance systems, the Multiphase Flow Meter (MPFM), due to the H2S variations, which can reach up to 5% within the same reservoir.
Design and Installation of the Submerged Loading System
Authors: Vedeld Stein , Frichou Adeline 
Published: July 2009

Abstract
Talisman Energy Norge AS has awarded a contract to SBM Offshore for the re-development of the Yme field which is located in the Egersund basin in the North Sea. The re-development is based on a Mobile Offshore Production Unit (MOPUstor) with a subsea storage tank from which stabilized crude is exported via a Submerged Loading System (SLS).
The SLS, which is a novel design, is a freely weathervaning loading system located directly on the seabed. The SLS consists of a subsea flowline fitted with a horizontal diverless connector at each extremity, and a gravity base with a rotating upper part linked to the export tanker through a 16?? ID riser in a Steep Wave configuration. When disconnected, the riser is left on the seabed, and the end of the riser is connected to a messenger line which is terminated by surface marker buoys and a pick-up rope.
Both the riser and the flowline are comprised of 12m Trelline™ bonded hose sections. The riser (or any hose section) is replaceable by way of a vertical diverless coupling connecting the gravity base piping and the subsea central pipe swivel.
An acoustic transponder with heading sensor is fitted on the rotating part of the subsea swivel, and acoustic DP reference transponders are positioned on the seabed.
The SLS system is hawserless because it is operated with DP Class 2 tankers which can stay on station up to the maximum specified operational seastate.
The SLS was installed by SBM's Normand Installer in August 2008. This was the first major milestone in the MOPUstor system installation campaign. The size of the gravity base and the large number of bonded hoses (115 hoses for the flowline and 16 hoses for the riser) made it a challenging operation, not only offshore but also at the mobilization in port. The constraints onshore and offshore, the main installation steps and the methodology are described in this paper.

Introduction
The Yme field is located approximately 100 km offshore in the Norwegian Continental Shelf. The Yme field consists of two main reservoirs, Beta and Gamma, which are approximately 12 km apart. The Yme Re-development Project will be based on a MOPUstor2,4, which is a Mobile Offshore Production Unit with a subsea storage tank. The MOPUstor will be located at the Gamma reservoir with surface completion of the Gamma wells and tie back of the subsea completed Beta wells.
The oil will be exported by means of an oil offloading flowline laying on the seabed and a weathervaning Submerged Loading System (SLS) installed in the vicinity of the MOPUstor at a distance sufficient to allow weathervaning of the shuttle tanker, as shown in Figure 1.
Export tankers will periodically connect to the SLS and will receive the oil stored in the storage tanks of the MOPUstor.
The complete system is designed to meet the environmental operational conditions specified for both the offloading and survival cases in accordance with the specifications and the Classification Society rules. The SLS system does not require mooring because it is attended by DP tankers.
SS - I-Field Implementation Enable Real Time Reservoir Management Of Newly Developed Saudi Fields
Authors: Al-Malki Said Saad , Al-Buraikan Meshal , Abdulmohsin Rami Ahmed , Wolfe Wayne , Harbi Asem , Al Shaikh Abdulsatar Ahmed 
Published: July 2009

Abstract
This paper demonstrates how intelligent Field (I-Field) capabilities, including the Enterprise Monitoring System (EMS), are being used in real time to monitor the performance of 11 reservoirs across three Saudi Aramco carbonate Fields to meet the required crude blend, and to provide alerts to engineers when certain reservoir engineering requirements or strategies are violated. Using a real Field example, the paper discusses in detail an I-Field workflow used to monitor reservoir performance during a pre-injection period, starting from real time data gathering, validation and mapping, using Permanent Downhole Monitoring Systems (PDHMS) and integrated surface and subsurface modeling along with data mapping packages. Finally, the paper illustrates how integrated real time data and modeling results are used to optimize production and injection strategies for the three Fields for more efficient real time reservoir management.

Introduction
During the planning phase for developing a new increment in Saudi Arabia (Figure 1), several challenges were identified suggesting the need for putting eight of the project's eleven reservoirs on power water injection to add reservoir energy prior to oil production start-up [1].
Tight flank permeability preventing enough aquifer support from reaching the crest area of the Field was identified to be a challenge for meeting production target of two of the eleven reservoirs. Long reach flank injectors with ± 2-km of reservoir exposure were recommended as the optimum solution to provide adequate injection rates to support producing area in two reservoirs [1].
Presence of a non-permeable tar mat across the flanks of the Field preventing aquifer support from reaching the producing area was identified to be a challenge for meeting production target of four of the eleven reservoirs. The need to drill or reactivate up-dip injectors placed ±30' above the tar-oil contact (TOC) was recommended as the optimum solution to provide adequate injection rates to support the producing area. Optimum well placement above tar was selected based on a massive data gathering project that was initiated to map the tar mat. Several studies were conducted to confirm minimum impact on ultimate recovery of wedge oil [2].
Innovative Solution for Emergency Repair of a Deep Water Riser (Avoiding Flooding and Re-Commissioning, Minimizing Lost-Production) A Case Study of Independence Hub Flex-Joint Repair
Authors: Selden Rush 
Published: July 2009

Abstract
The export riser leaving the Enterprise Independence Hub platform is a 13,000 feet, 20?? SCR, in 8,000 feet of water, with the capacity to handle more than 10% of the natural gas transported from the Gulf of Mexico.
In April 2008, Enterprise found a leak in the flex-joint assembly, located about 26 meters (85 feet) below sea level.
The goal was to repair the flex-joint with minimum down time. Normally the valves above the assembly would be shut and the flex-joint disconnected to replace the o-ring. This would cause the riser to flood, and once repaired, the riser would have to be de-watered and re-commissioned.
This paper will discuss the repair, using an innovative technology consisting of a remotely controlled (through-steel wall data communication) double block, piggable high-pressure isolation system (non-invasive). The system was pigged from the platform launcher, through the riser, and " set?? immediately past the flex-joint.
Once the flex-joint was so isolated from the riser with this tool, the o-ring gasket was replaced subsea (at ambient), without flooding the remainder of the riser or pipeline, avoiding degassing (the riser and pipeline remained pressurized during repair) and avoiding re-commissioning.
The repair was completed, and Enterprise was able to resume gas flow, in 10 days, representing a significant savings in lost-production.
Considering MMS Safety Alert 264, and with deep water risers becoming more common, and more valuable given their high pressure/volume of production, this pressure isolation technology represents a method of allowing subsea repairs without flooding, potentially saving months of production.
Improvements in Dynamic Loading of Ultra Deepwater Catenary Risers
Authors: Wajnikonis Christopher John , Leverette Steven J. 
Published: July 2009

Abstract
This paper gives results of numerically modeling several examples of steel catenary risers (SCR's) with a variety of buoyancy and damping devices. Conventional and modified strakes, short segments of conventional plain cylindrical floats, and modified buoyancy units were investigated. A key configuration studied is a " short-lazywave?? configuration where buoyancy is used on the lower section of riser of length equal to 10% of the water depth. The dynamics of variations of the short-lazy-wave SCR's are compared with that of similar conventional free hanging SCR's.
The variations and modifications of the buoyancy units and of the strakes involved adding damper/added mass surfaces, so that those devices increased the riser drag per unit length in up to three local dimensions: in the tangential, normal and bi-normal directions. The dampers can be installed on the riser in-between the conventional devices (i.e., strakes and floats). They can be attached to those devices or they can be built integrally with those devices. The devices investigated can be used with newly installed risers, but are also suitable for retrofitting existing risers.
The touchdown zone (TDZ) fatigue is one of the important design considerations of SCR's. In addition to controlling the SCR design, TDZ fatigue is significant enough that it can affect the selection and design of the production vessel. For the riser examples shown, most of the improvements achieved over the base case conventional riser were due to the decoupling character of the short-lazy-wave. The variations investigated resulted in a considerable increase in the TDZ fatigue life of the modified SCRs - fatigue lives were increased by between one to three orders of magnitude. In the cross and near configurations, using dampers on the buoyancy allowed fatigue life improvements above those pertaining to plain floats by factors of 1.05 to 4.4. Effective tension compression was eliminated. Mean and maximum dynamic hang-off loads were decreased 13% to 24%. The configurations investigated may allow reductions in pipe wall thickness for new risers and they allow the use of SCRs in water depth/metocean conditions where it may be difficult or impossible to use free hanging risers. Of particular note is the possibility of using SCR's from FPSO's and semisubmersible in conditions which have heretofore been considered limiting.

Introduction
SCRs are commonly used in deep and ultra-deep water; they have traditionally provided a low cost and reliable solution for export lines and flowlines to/from remote wells and floating systems.
Design controlling limitations in use of SCR's are typically fatigue due to dynamic stresses at the top and in the touch down areas, and compression in large motion conditions. Fatigue due to dynamic stresses may also become more troublesome in particular where sour service is combined with high design pressures.
SS: Spar Technology - Marine operations during transport and discharge of SPAR hulls
Authors: Postma Ralph 
Published: July 2009

Abstract
One of the key elements of the production & installation of a SPAR floating production unit is the transportation of the hull from the construction yard to the installation area. Given the specific geometry of SPAR hulls unique operational challenges are to be overcome. These challenges, as well as the engineering and operations aspects, will be adressed.
The paper describes the way these marine operations are prepared and executed on site. Lessons learnt during execution of SPAR transports are provided as well as statistics that can be produced, based on the many SPAR hulls that have been transported on Heavy Transport Vessels (HTV).

During the loadout phase
Potentially critical aspects have been identified and evaluated in this chapter, based on the assumptions below.

Assumptions
The following is assumed for the load out review in this chapter:–Load out will be a stern load out by means of skidding–The SPAR load distribution will be as defined in Attachment 1.–Skidding arrangement will be situated below soft tank, heave plates and hard tank.–the soft tank generally exceeds the vessel perimeter and as such, it is not supported during the voyage/ load-out–Hard tank skidding arrangement will be positioned at the load centre.–Heave plate support design is such that the load is dispersed along a length of 15m and in general aligned with the vessel's longitudinal bulkheads.

Ballast capacity of the HTV
For a stern loadout, the main parameters for the feasibility are:the quayheightwater depthtidal fluctuationweight distribution of the SPAR.
To verify that the vessel has sufficient ballast capacity for the stern loadout, several ballast conditions are prepared. A prerequisite for the skidding operation is that the skid beam on both the quay and the vessel are aligned horizontally. This requires the vessel to be in an even keel condition.
In addition a check is performed to verify that sufficient ballast capacity / flux is available to account for tidal fluctuations as well as the compensation for cargo weight during the load-out operation. The analysis results in a minimum draft at which the operation can be performed.
The water depth of the load out location needs to be sufficient to guarantee a vessel under keel clearance of ~1.0 m.
Hybrid Screw Compressor Suitable for Offshore Vapor Recovery or Flare Gas Elimination Application
Authors: Fujimatsu Kenji 
Published: July 2009

1. ABSTRACT
Environmental issues such as global warming are getting widespread international attention. Flare Gas Elimination projects and Flare Gas Recovery systems become more interest among oil and gas industries all over the world. Screw compressors are suitable for gas compressor applications that can recover flare gas or the hydrocarbon vapor instead of sending it to a flare line for offshore platforms or FPSOs (Floating Production, Storage, & Offloading). This type of compressor system provides Zero Flare Emission.
Oil-free screw compressors have been used for process gas applications since the 1970's. Oil-flooded screw compressors have been used in many process gas related applications since the 1980's. Recently, both oil-free and oil-flooded screw compressors have been expanding into the process gas compression application industry.
The oil-free screw compressor is popular for the offshore applications in recent market trends, and it has been used due to several advantages, good suitability and reliability in comparison to other types of compressors.
Hybrid Screw Compressors have been developed by creating the best combination of advantages in the oil-free and the oilflooded screw compressor.
Hybrid Screw Compressors have good features of compact and reliable designs, simple single skid arrangements. These features translate into benefits for the users such as lower installation costs, simple and easy start/stop operation, and suitable for long-term continuous operation.

2. INTRODUCTION
The purpose of this paper is to present technical information and advantages in Hybrid Screw Compressors, and also show a comparison to the conventional type of Oil-free and Oil-flooded Screw Gas Compressors. In addition, the paper will explain what benefits the Hybrid Screw Compressor provides to vapor recovery and flare gas elimination applications in the offshore areas.

3. HISTORY
Since the screw compressors have characteristics of both rotary (centrifugal) compressors and positive displacement compressors (reciprocating), screw machines found rapid acceptance in petrochemical and gas processing industries. In 1975, API 619 was introduced to specify a screw compressor. This first edition of API 619 looked only at oil-free screw compressors. During this period, the oil-free screw compressor was applied in many unique applications such as butadiene, styrene monomer recycle gas, linear alkyl benzene, soda ash, etc. Most of these applications are subject to dust, polymers, and liquids that are likely to be present in the gas stream. In many cases, water injection was used to control the compression process.
In the 1980's, oil-flooded screw compressors started appearing in process gas applications. During the same period of time, cogeneration started to take off with gas turbines becoming necessary in more and more applications. Also, oil-flooded screw compressors were finding their way into light gases such as Helium and Hydrogen.
SS: Agbami Field Development: Incident and Injury-Free Culture: A Journey to Achieve World Class HES Performance
Authors: Simon Rick L. , Duncan Lorri 
Published: July 2009

Abstract
The Agbami Project is a unitized development. Star Deep Water Petroleum Limited, an affiliate of Chevron Corporation, is the operator of the Agbami Unit, The concessionaires are Famfa Oil Limited and Nigerian National Petroleum Corporation and the other partners are Petroleo Brasileiro Nigeria Limited, Statoil Nigeria Limited and Texaco Nigeria Outer Shelf Inc., a Chevron Corporation affiliate. The Agbami Project achieved outstanding safety performance during project: Execution, Installation, Hook-up and Commissioning. The major keys in achieving world class safety performance were the focus on: Incident and Injury Free (IIF) Culture development, Training, Safe Facilities Design, Operational Excellence, Risk Management, Safe Job Analysis, Incident Investigation and Reporting, Emergency Response and Contractor Management.
This paper will provide a look back into the major safety challenges and solutions that occurred during the Phase 4: Execution, Fabrication, Hook-up and Commissioning and Hand Over to operations phase of the project. Some of the major project HES milestones will be reviewed as well as HES statistics to help develop a better overall appreciation for the Agbami Project's safety implementation and performance.

Results, Observations, Conclusions
In conclusion the development of an Incident and Injury Free (IIF) Culture is critical in achieving world class safety performance for major capital projects. There is also the need to have mature safety processes in place and functioning i.e.: Safe Facilities Design, Operational Excellence, Risk Management, Safe Job Analysis, Incident Investigation and Reporting, Training, Emergency Response and Contractor Management. All of these elements along with top down management support, commitment and leadership help drive excellent safety performance and organizational capability. Over time through the sharing of Lessons Learned, a Safe Culture as well as a Learning Organizational Culture will develop. The development of this dual culture will promote the cycle of continual improvement and enhance better safety performance.

Significance of Subject Matter
The importance of reviewing the " Safety Journey of the Agbami Project?? is to assure that the Lessons Learned are shared, benchmarked and communicated to stakeholders and interested parties. This will assure continual safety improvement in the execution of major capital project's (MCP's) industry wide.
Moho Bilondo: The First Deepwater Development Offshore Republic of Congo
Authors: Cahuzac Claude , Bourcier Franci 
Published: July 2009

Abstract:
After onshore development more than 40 years ago, standard development in water depth around 200m, Total Exploration Production Congo has launched in 2005, with its partners SNPC and Chevron, the development of the Moho Bilondo field, the first deep sea project offshore the Republic of Congo. The field was brought in production in April 2008, 33.5 months only after award of the execution contracts.
This paper presents the specific challenges met by the Operator, to make this " mid size?? deep sea field an economical development, the compact lay-out selected, the technical choices in drilling and completion for instance and the organization with early integration of operators in the team which made this development a success.
Moho Bilondo which came on stream on April 17th, 2008 is the first deep offshore field of the Republic of Congo. This development is launching the valorization of a serie of deposits located about 80 km off the coast in water between 540 and 660m metres deep.
Four reservoirs hace been discovered on the Moho Bilondo permit since 1995, but Total Exploration & Production Congo and its Partners, SNPC, Société Nationale des Pétroles du Congo, and Chevron have opted to develop them in two stages. In the first phase of the overall development, only two deposits, Mobim and Bilondo, covering an area of about 72 sq.km in the southern part of the zone, are been brought into production. This strategy has allowed Total to meet the key challenge on Moho Bilondo: economical production of medium-sized reservoirs under the extreme conditions associated with deep water
Meeting this challenge meant to adapt the organization of the project to the specifity of the country, to solve technical challenges by innovation, selection of architecture and during operations with a challenging overall planning

A compact development scheme, developed with synergies with existing fields
In order to reduce development costs, one aim of the development scheme designed for this project was to minimize the subsea infrastructures necessary by reducing the number of wells and shortening the flowlines. The scheme provides for two groups of wells, one on each reservoir, drilled from the subsea clusters located 2,300 m metres to each side of the floating production Unit (FPU). However; achieving such simplicity in a subsea production system necessarily means very complex well trajectories.