bluuebunny/crossref_metadata_2025_split huggingface dataset:
Gimboa, Angola Block 4 - First Deep Water Challenge for Sonangol P&P
Authors: Wime H. , Nogueira Yuri A. , Fernandes Lucas Kiteque , Eriksen Gunnar , Bondevik Jon Olav 
Published: July 2009

Abstract
The deep-water (700 m) Gimboa field in offshore Angola was discovered in 2004. With approximately 50 million barrels of recoverable oil in place, this project is marginal at best. The development required accurate resources determination, cost effective implementation, and maximum recovery of the reserves. This is also the first deep water development by Sonangol Pesquisa & Produção, the National Oil Company of Angola, as Operator.
The short-term project (approximately 4 years from discovery to production) was loaded with uncertainties and risks. Among the technical challenges were performing the conversion of an oil trading tanker to an FPSO, the manufacturing and deployment of subsea production facilities as a tie-back to the FPSO, and the solution of issues related to low reservoir pressure, gas lift, water injection and insulation.
In order to tackle these difficulties and quickly build expertise, the Operator formed a technical assistance agreement with one of the concession partners. Engineers, geoscientists, and managers from both companies worked together, as one co-located team with shared objectives. Effective communication using the web and management were key factors to ensure that the project team and the globally distributed team of vendors could focus on the work at hand. After successfully meeting all the challenges, the field is scheduled to enter into production at the start of 2009.
An equally important result of the Gimboa development was the self-realization by a relatively young national oil company that they could manage and develop complex projects in difficult environments. This project also demonstrates that regional and global organizations can equally benefit from the introduction of innovative and more open partnership models.
The paper summarizes the Gimboa experience, and describes how national oil companies, with the appropriate focus and technical assistance, can successfully and quickly develop their marginal discoveries, making the most of the available fiscal incentives, using national resources, and promoting local content.

General Overview and Description of the Field
Focus so far by the Operators in West Africa has been on major oilfields, initially in the shallow water regions or on land in the north of Angola. But, in the last decade this has moved into the deep water environment. However most of the major discoveries, being in deep water are currently under development or are already in production. Focus, will therefore soon be turning to develop fields of smaller sizes in this type of environment.
Recent high oil prices driven by several factors is providing the opportunity for small and independent Operators such as emerging national oil companies to be able to develop those smaller fields which otherwise would be deemed uneconomical especially if they are located in deepwater or far away from offshore infrastructure.
A Cyclone-Based Low Shear Valve for Enhanced Oil-Water Separation
Authors: Husveg Trygve , Bilstad Torleiv , Guinee Peter , Jernsletten Jo , Knudsen B. , Nordbø Hans Tore 
Published: July 2009

Abstract
Turbulence and shear in conventional choke and control valves do mix and emulsify petroleum fluids. A typical consequence is reduced separation efficiency of downstream gravity separators, resulting in retarded oil-water separation. A new cyclone-based low shear valve is developed, enhancing oil-water separation and reducing environmental impacts from petroleum activities. Five years of experimental and theoretical studies are reviewed, including recent tests involving six different North Sea crude oils. For a majority of oils the cyclonic valve has a significant positive effect on oil-water separation. Moreover, it is documented that the cyclonic valve has an overall positive effect on both oil-in-water and water-in-oil concentrations, across a large range of water cuts. The cyclonic valve has a consistent positive effect on oil droplet size for all crude oils in produced water. Typically, oil droplet effluent from a cyclonic valve has twice the size of droplets exiting a standard valve. The effect is largest for the smallest volumetric fraction of droplets. This new valve technology is realizing great potential in petroleum processing; i.e., less droplet break-up and less fluid emulsification. This paper demonstrates quality improvements for both crude oil and produced water. Replacing choke valves might be the ultimate application for cyclonic valves. However, experimental results demonstrate that control valves upstream any gravity-based separator are potential targeted applications for cyclonic valves.

Introduction

Valves in Petroleum Production
Valves are widely distributed in petroleum production and hydrocarbon processing facilities (Figure 1). In their operation throttling valves possess an effective restriction to flow. Choke valves and control valves are typical throttling valves used to regulate flowrates and pressures of fluids in a petroleum process.
Flow Assurance Benchmarking--Bridging the Gap Between Initial Design and Ongoing Operations
Authors: Ng Chris , Tadimeti Krishna , Lowry Timothy 
Published: July 2009

Abstract
A brief overview of the flow assurance benchmarking process is presented, followed by a discussion of typical flow assurance problems identified during benchmarking studies, a couple of examples showing how benchmarking adds value to field operations, and lessons learned that can be applied to flow assurance studies for ongoing operations and future projects. The types of computer models described in this paper could be used to track and interpret field data, evaluate and improve field performance, and to identify and mitigate potential flow assurance problems during subsea production operations.
Actual field data are incorporated into the two examples of flow assurance benchmarking. Specifically, the first example involves malfunction of a subsea tree choke valve during the first few months of production. The second example involves potential failure of flowline insulation or sensor malfunction. This paper adds to the current body of knowledge regarding the modeling of subsea production operations and provides guidance on improving models used in flow assurance analysis.

Introduction
The flow assurance challenges and mitigation strategies typically associated with deepwater projects have been discussed at length in multiple papers [1,2]. Production fluid behavior during steady-state and transient operations need to be understood adequately in order to maximize production, minimize costly downtime, and develop effective strategies to prevent flow assurance problems.
The flow assurance benchmarking process is a key step in bridging the gap between engineering design and successful field operations. The primary goal of this process is to develop an accurate and integrated quantitative model of the production fluid behavior within the constraints of the as-built field architecture and actual environment. With a reliable model, engineers and operators can better understand the actual operating limits, identify and monitor deviations from operating targets, anticipate and avoid operational problems, implement effective operating strategies and procedures, and plan for future operation and field development.
An overview of the benchmarking process is presented in this paper, together with a couple of examples demonstrating how effective benchmarking can be used to alert operators to potential equipment failure and avoid unexpected downtime.

Benchmarking process
A typical benchmarking process involves the following high-level steps:Define the scope, objectives and acceptance criteria.Gather required model input data, including operating data.Develop thermal-hydraulic model (steady-state and/or transient).Compare operating (measured) data to model-calculated values.Revise model until acceptance criteria are met.
Flexible Riser Outer Sheath Full Scale Wearing Simulation and Evaluation
Authors: Clevelario Judimar Assis , Sheldrake Terry H. , Pires Fabio , Falcao Gelson , Souza Italo , Aquino Fabio 
Published: July 2009

Abstract
The interface between the flexible risers and I tubes is being considered by the market as a critical region due to its geometric characteristics and high contact loads between the flexible risers and I tube interface equipment. During the past few years several instances of outer sheath damage were reported by the offshore industry. Such damage was a result of wear against steel parts and occurred in the regular design adopted by the industry, causing riser annulus flooding which significantly reduces service life.
Some of the most severe riser failures reported indicate the rupture of the outermost tensile armour layer. Wellstream has designed and patented a new concept for riser interface equipment by adopting a split and replaceable polymeric insert designed to be in direct contact with the riser's outer sheath.
Wellstream is currently performing a 12 month alternative dynamic test using a 9.13 inch gas export riser as part of the qualification programme; the interface between the outer sheath and the polymeric insert is under peer evaluation. As part of the test, the evaluation of the wear considers actual flexible riser service fatigue loads and actual relative displacement between the riser and polymeric insert in order to reproduce field service conditions. This paper presents the wear evaluation performed during the dynamic test, which also includes UT and laser scanning measurements to monitor and assess the wear on both the riser's outer sheath and the polymeric insert. The test results indicate that the proposed design, which adopts the polymeric insert, is capable of preserving the outer sheath throughout the riser's service life thus demonstrating that it resolves the problems reported by the industry.

Introduction
Floating production units used for offshore oil and gas exploration employ flexible pipe systems and may present two different kinds of configuration at the platform. In the first type, referred to as ‘direct’, the bend stiffeners and interface equipment are assembled directly onto the pipe's end fitting on the platform's riser balcony. This does not lend itself to wear-related problems since the distance between the end fitting and the interface equipment is so short that pipe axial deformation, due to service loads, may be considered negligible thus drastically reducing, or even eliminating, the possibility of damage to the pipe's outer sheath due to wearing.
SS - Application Of Artificial Lift Technology In The Giant Khurais Field
Authors: Al-Somali Abdullah Ahmed , Al-khanafair Nabil , Pomeroy Peter , Al-Towailib Assad , Al-Shammari Awayyid 
Published: July 2009

Abstract
This paper discusses the basis of selecting Electrical Submersible Pumps (ESPs) rather than the other methods of Artificial Lift in the development of the Khurais area, located in Saudi Arabia. It will also discuss the production strategy, project time line, design methods and well performance utilizing an online monitoring system.
Khurais oilfield development is the largest oil increment in the world scheduled to be placed on-stream in 2009. The Khurais increment will add 1.2 million bpd of high-quality Arabian light crude to Saudi Arabia's production capacity. To increase the field's production, several options were evaluated and Artificial Lift utilizing ESPs was chosen as the most viable option for optimizing the Khurais production.
Artificial Lifting by ESPs, in different Saudi Arabian fields including Khurais, was designed to serve several different objectives. The primary objective is the need to increase production from oil wells and fields. From a flow assurance point of view, ESPs have been used to boost wellhead pressures rather than enlarging gathering facilities to reduce the system backpressure. This mandated installation of surface control, safety shutdown, and surface & subsurface data acquisition systems along with supervisory control and monitoring equipment in control rooms.

Introduction
The Khurais area fields (Fields A, B and C) are located about 160 km from the Saudi Arabian capital, Riyadh. Khurais increment will have the capacity to produce 1.2 MMBCD of Arabian light crude by end of 2009. Field A will provide the majority of the production capacity with 1.0 MMBCD, Field B will provide 110 MBCD and Field C will contribute 90 MBCD. Prior to starting production, a six-month preinjection will be initiated to inject 2 MMBCD of treated seawater.
Field A is the largest field in the increment. It was discovered in 1957 and first produced in 1963. The field is about 90 km in length and the width ranges from 5 to 17 km. There are three oil-bearing carbonate reservoirs. Arab Light crude production started from the one reservoir in 1963 and in 1981 a second reservoir was put on line. The third reservoir was never produced.
SS: MODU Risk- Post Mortem Analysis of MODUS in Hurricanes Katrina and Rita
Authors: Sharples B.P. Malcolm , Stiff John James 
Published: July 2009

Abstract
A number of hurricanes have passed through the Gulf of Mexico resulting in MODUs parting moorings or collapsing, but none have come close to the devastation caused by Hurricanes Katrina and Rita which came through the Gulf of Mexico in August and September 2005. 20 semi-submersible MODUs suffered some level of significant mooring impairment, and 8 jack-ups were declared total losses (with many more suffering additional settlement and other damage). While this was a severe outcome for the MODU fleet, which had previously experienced relatively few failures1 due to storm overload, over 100 platforms were destroyed, and the hurricanes caused disasters and major regional devastation on land. This paper reviews the level of damage to the MODU fleet caused by the two hurricanes.
Much can be learned about the likelihood and consequences of future failures by studying past experience. Information on the location of where mooring component parted helps assess the consequences of those mooring lines parting, and the site details for the jack-ups help point towards the drivers for their survival. These can then be put into the perspective of other structures of the industry.
Semisubmersible MODUs in the Gulf of Mexico have changed their general usage since development of the API RP2SK [ref.1] to which their moorings are designed for individual locations. The consequences of MODUs drifting in an extreme hurricane are potentially much greater than in the past because of the recent development of the deep water, highly productive, platforms and their associated extensive subsea infrastructure. Damage to this highly productive infrastructure is detrimental to both the nation and industry.
In the aftermath of these hurricanes, which followed Hurricanes Lili, and Ivan, the industry re-examined and upgraded the standards for siting MODUs. An industry driven JIP was launched on moored semi-submersible MODUs which chronicled the incidents and provided guidance for the change in standards. The MMS commissioned a study on the jack-up failures and successes and industry developed a new standard for jack-ups, API RP 95J. Together with MMS-NTLs, these documents provide guidance for siting MODUs to avoid future multiple losses, minimize consequences of failure, and increase the probability of survival.
Measuring Oil in Water: A Sanity Check
Authors: Brown Lew , Ide Mason , Wolfe Peter 
Published: July 2009

Abstract
Reliable measurements of oil in water are becoming increasingly important to the petroleum industry. As the percent content of water in crude climbs higher, the need to increase the percent of oil recovered from the water treatment systems also climbs; efficiency in water removal corresponds directly to the bottom line for oil producers.
Additionally, particularly on offshore platforms, there are stringent environmental regulations which need to be met.
The majority of well-proven techniques for measuring oil in water are " laboratory based??, typically using either gravimetric methods or IR (Infrared) Spectroscopy. However, lab-based measurements are too time-consuming for the realities of production environment. In particular, a water treatment system really needs to be monitored in several places in order to determine the efficacy of each treatment stage (and also for troubleshooting the process). This really requires an on-line or at least " at-line?? monitoring approach for best results.
Over the years, several different methods have been proposed and used in the industry in order to accomplish real-time monitoring of oil in water content. Some of the more common methods tried include UV (ultraviolet) fluorescence, light obscuration, acoustic backscattering, IR absorption and digital imaging. All of these techniques claim to be able to measure oil in water accurately.
In this paper, we will take three actual instruments and compare their results against a standard EPA testing lab results. Solutions of known oil in water concentration were mixed in the laboratory, and samples of each were run through the different instruments and also sent in parallel to a certified EPA testing lab. The results were then plotted together to get a snapshot view of how each instrument did versus the results from the independent lab. The results show that all techniques exhibit variance, and that no two instruments produce the same result. The point of this exercise is not to " prove?? that any one technique is more accurate. Rather, the point to be made is that manufacturers' specifications for accuracy should be at least " calibrated?? to known and accepted measurement techniques.

Why Measure Oil in Water?
Reliable measurement of oil in water, particularly in produced water, is becoming increasingly more important. Initially, measurement of oil in produced water was being driven primarily by environmental regulations, particularly those imposed on offshore operations. However, as the world's supply of oil becomes smaller, the price continues to rise and extraction is taking place on supplies having higher water content. In light of this, the need to more carefully monitor oil extraction from water has increased dramatically. Not only do the oil producers want to extract the most possible oil from the supply, but the environmental regulations are becoming more stringently enforced with time.
Casting and Forgings for Offshore Structures and Moorings
Authors: Marshall Peter W. 
Published: July 2009

Abstract
Following recent difficulties with the jewelry in deepwater moorings, a number of attendant issues have identified, which were reviewed in a " white paper?? prerared in the spring of 2008. The author's background is in practical fracture control standards for fixed platforms and hull structures, offering a fresh (naïve?) insight into the following topics:system reliability,geometric design,Manufacture & QCincorporation into the overall construction,operation, inspection and maintenance, and the way forward

Introduction
There are many offshore applications of castings and forgings. Although the primary focus of the author's work is specification of materials and welding for fixed platforms, it is mooring jewelry in projects such as Kikeh and Tahiti that has become a cause for concern in recent months.
Yield before fracture is the prevailing philosophy in designing critical components of permanent fixed offshore platforms and marine hull structure. Observable deformation gives a warning of impending failure. If there is less ductility, the component " fails ugly??. In structures, this is considered undesirable, even if the load capacity is almost the same. In mooring lines, with no redundancy and no warning, both modes of failure have the same consequences.
The cast mooring socket in Figure 1 is an example of " failing ugly??, from the MMS post mortem of hurricane Ivan [2]. Mooring jewelry is typically designed not to fail before the wire or chain. The first of 8 mooring lines on the semi-submersible MODU failed at the expected location (rig wire at the fairlead). However, as the system unzipped, there was one failure at an in-line connector, and a padeye failed after being loaded out-of-plane. The rig's drift path hooked around and came within five miles of hitting the Nakika hub. Had it hit the LOOP facility, the estimated $30 billioin economic disaster for the nation (not just oil companies) would be on the same order as losing 300 ICAF lives.
SS: Cryogenic Pipeline-Mechanical Design of Subsea and Buried LNG Pipelines
Authors: Brown Trent S. , Jukes Paul , Sun Jason 
Published: July 2009

Abstract
Design of subsea and buried LNG pipelines presents challenges such as low operating temperatures (-160 ºC), multiple pipe walls, and differential expansion of materials. ITP has developed an LNG pipeline design that has been certified by DNV as " Fit for Service?? for LNG subsea transport. JP Kenny has developed and applied a comprehensive FE model to ITP's triplewalled (PIPIP) LNG pipeline design to successfully demonstrate the robustness of the pipe design. The FE model is used to determine the displacements and stresses in each of the three pipe walls under all the operating conditions and to provide input data for detailed analyses of the bulkheads, risers, riser supports, and tie-ins to external piping. The basis of the model is presented along with a description of the PIPIP. Typical results of the modeling are presented, which demonstrate how the design of the PIPIP limits the stresses, displacements, and end loads. The use of the model results for design of ancilliary and connecting systems is also reviewed.

Design Considerations for LNG Loading/Offloading Pipelines
LNG loading/offloading pipelines present several design challenges:Low temperatures (-160 ºC)Relatively long distancesHigh thermal performance requirementsLow risk tolerance
The material selected for LNG pipelines has traditionally been stainless steel 304L. Although suitable for the low temperature, 304L has the disadvantage of a high Coefficient of Thermal Expansion (CTE = 13.6 × 10-6 K-1 between ambient and -160 ºC). For the stresses in a 304L LNG pipeline to be acceptable, the pipeline must be allowed to contract with temperature. Consequently, either expansion loops or bellows are required.
Heat ingress to the pipeline must be limited for operating cost and operational (Boil-Off Gas) reasons. As such, very low overall heat transfer coefficients (U-values less than 0.15 W/m2*K) are required. Low U-values have traditionally been obtained by using either Vacuum Insulated Pipe (VIP) or very thick conventional insulation.
All of the product from an LNG export facility must flow through the LNG pipeline. As LNG facilities involve high capital costs, there is a very low risk tolerance for LNG pipelines. If a subsea design is to be preferred over the conventional trestle design, the subsea design must be robust and able to withstand impacts that might occur in near shore regions with ship traffic.
To apply an LNG pipeline subsea, the thermal performance must be maintained; the design must be robust and reliable; and bellows and expansion loops must be eliminated. ITP has developed a design that satisfies these criteria using a triple-wall design with different materials for the pipes, and with bulkheads only at each end of the pipeline. The triple-walled design and bulkheads complicate the determination of the stresses, displacements, and end loads. JP Kenny has developed a pipeline analysis model that allows the design to be rigorously evaluated.