bluuebunny/crossref_metadata_2025_split huggingface dataset:
Ormen Lange Subsea Compression Pilot System
Authors: Bjerkreim Bernt , Frydenlund Snorre , Lie John Arild , Staver Knut Ola , Haram Karl Olav , Nystad Bjørn , Skofteland Håkon , Gedde Hans , Tesei Alberto , Postic Michel 
Published: July 2009

Abstract
Ormen Lange is a long tieback gas field developed with gas processing facilities onshore 120 km from the production wells. The development strategy is pressure depletion. In order to maintain the production plateau for as long as possible and recover the anticipated gas and condensate resources, offshore compression is required to maintain production.
This paper describes subsea compression as a cost effective alternative to the platform compression solution and the strategy for qualifying subsea compression system prior to offshore compression concept selection.
This paper further describes the subsea compression technical solution.

Introduction
Ormen Lange is a gas field located 120 km off the northwest coast of Norway on the Norwegian continental shelf, in water depths varying between 850 and 1,100 meters. The reservoir covers an area 40 km long, 8 to 10 km wide and 3,000 meters below the surface. Recoverable reserves are estimated to approximately 397 billion Sm3 dry gas and 28.5 million m3 condensate. Ormen Lange has been in production since October 2007.
Ormen Lange Subsea Compression Pilot - Subsea Compression Station
Authors: Skofteland Håkon , Hilditch Mike , Normann Truls , Eriksson Klas Goran , Nyborg Knut , Postic Michel , Camatti Massimo 
Published: July 2009

Abstract
Aker Solutions is the main contractor for the engineering, procurement, construction and installation of the subsea compressor station being built as part of the Ormen Lange pilot project. The compression station pilot is a full scale 12.5 MW compressor train which is equal to one of the four trains required for the permanent subsea compression station for the Ormen Lange gas field.
This paper describes the system design, equipment and subsea technology developed for the compression station pilot. The main part of the project has been to design equipment and technology fit for installation at 900 meters water depth and to ensure that the stringent requirements for reliability and robustness are fulfilled.
The process system is exposed directly to the wellstream at Ormen Lange and is designed to handle varying gas-condensate rates, liquid slugs and sand production. The main process equipment is the separator, compressor, pump and cooler. The high voltage power distribution system includes subsea circuit breakers, subsea transformers and frequency converters to drive the subsea compressor and pump. The electrical equipment is included in subsea enclosures with high voltage mating mechanisms between the units.
The control system is key component for the subsea compression station. The long tie-back of 120 km and the requirement for high speed closed loop control and high bandwidth communication to shore initiated development of new technology solutions. An all electrical control system is developed with subsea uninterruptible power supply and electrical actuators. A SIL2 rated Process Shut-Down System (PSD) is also included for additional protection of the subsea components. Communication subsea to shore is via fibre optic lines in the power umbilical.
Optical Permanent Monitoring System Meets the Subsea Challenge
Authors: Shand Michael M. , Birch Michael Charles , Bostick Tad , Tough Gary 
Published: July 2009

Abstract
In-well monitoring systems have now been developed which utilise permanent optical fibre sensing and can be deployed in the subsea environment. These optical monitoring systems are well suited for subsea deployment in terms of extended temperature and pressure regimes, along with reliability and advanced optical multiplexing technology.
Hundreds of optical sensors and millions of feet of optical cable have been successfully deployed in land and dry tree platform oil and gas wells since the early 1990's. In the last 1990's, a few prototype optical sensing systems were deployed subsea for single point pressure and temperature monitoring with partial success. However, over the last 10 years, optical sensing technology has progressed significantly, yet no subsea installations have been performed. This was not due to lack of interest but to significant challenges related to subsea deployment, and also in part due to projects cancelled for such reasons as perceived lack of data delivery infrastructure.
This paper describes how the significant challenges of subsea optical sensing were overcome through close cooperation between the operator and other 3rd party companies, along with extensive project organisation, custom engineering, and qualification testing and system verification. Deployment of the system took place offshore Angola in Q1 2008.
The major areas which we addressed in order to assure success were:Establishing standards to which the subsea instruments and components should comply with in order to build a robust test regime for qualifying the new optical sensing technology.Developing, qualifying and interfacing a subsea connector system for wellhead and tubing hanger penetration.Developing, qualifying and interfacing a new generation subsea optical instrument which would be deployed subsea in an atmospheric housing.Designing an in-well monitoring system which can deliver accurate reservoir pressure and temperature data from the sand-face to surface.
SS: Arctic: LNG STS Operations in Arctic Waters
Authors: Berg Tor Einar , Bakke Joachim 
Published: July 2009

Abstract
The LNG market is expanding, and development plans exists for LNG processing plants in Arctic Russia. This paper discusses a possible transport chain for LNG produced at shore-based terminals on the Yamal Peninsula. The recent disagreement between Russia and Ukraine on gas export to Europe has demonstrated the vulnerability of the present overland export system for natural gas. The planned North Stream will increase energy security for several European countries. However, a sea transport system may create a win - win situation for Russian gas producers and world-wide customers of natural gas.
The first part of the paper describes the individual legs of the proposed transport chain. The second part discusses ship-to-ship transfer of gas in general, followed by a review of LNG ship-to-ship transfer, and ends with a specific case, of which high-seas ship-to-ship transfer in Arctic waters is a critical element. The final part of the paper describes necessary developments in cargo-handling equipment and operational procedures for LNG transfer between two large LNG vessels in Arctic waters.
Ship-to-ship transfer of oil and gas is a routine operation in many parts of the world. A cost-effective transport system from Arctic LNG plants in the western part of the Russia to markets in Western Europe and east coast US/Canada could be achieved through the use of dedicated icebreaking LNG tankers transloading their cargo to conventional LNG carriers in ice-free waters in the Barents Sea.

1 Introduction
With the expected increase in demand for oil and decrease in production in certain areas in 2010 - 2020, pressure to develop the Arctic region is growing. The extreme conditions with ice and very low temperatures will make even more stringent demands of the ships, equipment and crew than normal. The Arctic is particularly sensitive and vulnerable, and the vision of zero harmful discharges is now generally accepted. A sharper focus on the part of IMO, EU and Arctic organizations, on environmental issues and safe operations will influence vessel operation. There will be a focus on new and innovative costeffective solutions to satisfy the strict requirements for ships and equipment from ship-owners, class societies, operators, the authorities and other stakeholders. The development of the Snøhvit gas field with its Melkøya LNG terminal has moved offshore gas production far north. Much larger offshore and onshore fields exist in the Russian sector of the Barents Sea and on the Yamal Peninsula. The recent problems with Russian gas export to Europe may increase pressure to develop an independent sea export route from the Russian European Arctic in addition to the planned North Stream pipeline. Current plans for development of LNG plants include a plant in Teriberka, where the Shtokman gas will be landed, and a facility on the Yamal Peninsula. Ship-based export from these plants will give the Russian gas company Gazprom access to both the European and North American markets.
Deepwater BOP Control Monitoring - Improving BOP Preventive Maintenance with Control Function Monitoring
Authors: Chapman Frank M. , Brown Ronald L. 
Published: July 2009

Abstract
The goal of Blowout Preventer (BOP) preventive maintenance is to reduce downtime due to equipment failures. A corollary issue is the reduction of unnecessary maintenance. This becomes increasingly important as the BOP control system ages or nears its five-year maintenance cycle.
Appropriate / timely proactive BOP maintenance can only be performed when accurate function cycle data is available. As such, an effective BOP preventive maintenance program requires accurate record keeping on all BOP function cycles - during drilling operations as well as during testing. Manual record keeping is generally missing or unreliable.
A system has been developed for (1) automatically monitoring and recording BOP control state changes, (2) transporting the state change data to a database server on shore and (3) analyzing and presenting the BOP information to interested personnel via the web. The system provides a detailed historical record of the BOP status. Using this data the number of valve cycles can be accurately counted and the valve cycle information can be used to estimate when maintenance is required for each valve in the BOP control system.
In addition, the information captured by the system can be used to troubleshoot BOP control issues and as input to evaluate BOP operational procedures.

Introduction
Proper maintenance of a rig's BOP is critical for insuring the safety of offshore drilling operations. In many regions of the world regularly scheduled BOP testing is a regulatory requirement. Unexpected BOP problems or failures can lead to significant downtime [Holand 1997, Holand 1999]. Fixing BOP problems can be extremely expensive, particularly if the problem or failure requires the marine riser and BOP to be round tripped. The various valves contained in a BOP control system and the number of times they are cycled is a significant factor affecting BOP reliability [Shanks 2003].
New technologies can be used to continuously and accurately monitor BOP operations over time. Having accurate historical information on BOP operations, valve cycles and pressures can lead to more proactive BOP maintenance programs. Better maintenance can, in turn, result in safer operations and reduced costs.
Over the years a number of new technologies have been integrated into offshore drilling programs. In most cases these technologies have resulted in improved operations and reduced expense. In many cases the next step to achieving improved operations and greater cost reductions is to integrate several existing technologies.
Qualification of LNG STS transfer flexibles according to guideline EN1474-II
Authors: Van den Beemt Bas , van Bokhorst Evert , van der Weijde Gerard D. , Mallon Niels , Verweij Sander 
Published: July 2009

Abstract
This paper will describe some lessons learned from the qualification process of 8?? cryogenic multi composite hoses for ship-to-ship transfer of LNG. The available guideline for certifying transfer hoses is the EN1474-II. In addition to this guideline, which was preliminary at the time of use, many other issues need to be detailed and until now leave room for further interpretation.
TNO proposed a multilevel test program combined with developing models that predicts the behavior of the hose system. The test program showed some remarkable results related to the mechanics of the hose. For example the hysteresis provides a damping mechanism for vibrations due to internal and external sources. Also extreme high damage tolerance behavior, in incidents the hose provides a high level of residual safety. The remaining burst pressure is still exceeding the burst pressure requirements of an undamaged hose and no jetting occurs.
With a full scale LNG flow test the flow behavior of the hose is extensively tested. For example the maximum flow of 1500 m3/h has been shown during this test and did not lead to unacceptable pulsation or vibration levels. The prediction model for the friction factor of the 8-inch hose, based on tests at ambient temperature with water, shows the correct trend. The pressure loss depends on the internal pressure in the LNG flow test, which shows the added value of this LNG Flow test.
The gained experience let to a number of recommendations for other LNG qualification projects. For example we recommend to combine tests with analyses to reduce the amount of testing for the complete transfer system and to be able to reapply the result for other configurations. Further specification of requirement than what is described in the EN standard is needed (e.g. excessive vibrations, what is stiffness, permeability). As long as further specification of the test is not provided in standards involvement in the definition of the test program of equipment supplier, end user, certifier and independent research contractor is needed. Finally the results proved that LNG test are still inevitable for flow equipment qualification and model validation.

Introduction
Dynamic transfer of LNG from ship-to-ship is seen as one of the enabling technologies to support a possible LNG supply chain offshore. LNG supply to regasification vessels or the offloading of a floating LNG production unit in the near future must be able to be performed under all weather conditions. The latter has made it necessary to develop alternatives to rigid loading arms, with an additional need for testing and certification. New transfer technologies and methods have to guarantee maximum terminal availability without making concessions to safety and operability. This paper will describe some lessons learned from the qualification process of 8?? cryogenic multi composite hoses for ship-to-ship transfer of LNG.
Tyrihans Subsea Raw Seawater Injection System
Authors: Grynning Audun , Larsen Stein Vegar , Skaale Inge 
Published: July 2009

Abstract
StatoilHydro's Tyrihans field development is located about 22 miles (35 km) south of the Åsgard field on the Norwegian continental and the oil production will be substantially increased by raw sea water injection.
The Tyrihans water injection system, currently manufactured and successfully tested, is the worlds most powerful subsea pump system and will have the longest step-out distance of 19.3 miles (31 km) to date. Two centrifugal pumps operate in parallel and have been verified by testing to be able to deliver a total shaft power of 7,340 hp (5.4 megawatts). The maximum injection capacity of the pumps is 126,000 bpd (20,000 m3/d) of seawater, without any filtration or chemical injection.
During the last year, the subsea pump system has been through full load performance, endurance, stability and system integration testing at Tranby, Norway. The paper presents the pump system design including the pump modules, barrier fluid system, power supply, control and monitoring system. Data from the performance testing is included and discussed.

System overview
The StatoilHydro operated Tyrihans field is located on the Norwegian continental shelf approximately 22 miles (35 km) south of the Kristin and Åsgard B Platforms. Tyrihans will be developed with 5 subsea templates including oil production, gas injection and one raw seawater injection template (W). The subsea production system will be tied back to Kristin through a 16/18?? oil production flowline and receive gas for injection from Åsgard B through a 10?? gas injection flowline.
Aker Solutions delivers the subsea raw seawater pump system and FMC was awarded the contract for the Subsea Production System for Tyrihans. StatoilHydro's contract strategy was to award this contract prior to awarding the contract for SRSWI and to invite the prequalified pump system suppliers to tender a pump system that could be lowered into the dedicated water injection template and controlled by the standard production control system.
Flexible Flowline Thermal Exchange Coefficient Test Performed at High External Pressures
Authors: Pires Fabio , Clevelario Judimar Assis , Falcao Gelson , Souza Italo , Sheldrake Terry H. 
Published: July 2009

Abstract
It is known that the thermal exchange coefficient (TEC) of an insulated flexible pipe may be affected by both external pressure due to the operating water depth and by the annulus condition. International standards state that flexible pipe systems shall be designed considering the effects of these two environmental conditions. If not considered during the flexible pipe design phase, these factors may have an important impact in the production system by reducing the temperature and allowing hydrate and paraffin formation in the pipe bore.
As part of Wellstream's research and qualification programme, a TEC test was performed to assess and quantify the effects of external pressure and the annulus condition during the flexible pipe system operation. The test was carried out using a 3m long sample taken from a 6 inch internal diameter production flowline designed to 1500m water depth and a maximum fluid temperature of 60°C with 276 bar internal pressure. Special end fittings were designed to reduce the pipe axial heat loss during the test.
The tested pipe was designed in accordance with Wellstream methodology and design tools to provide a pipe structure with a TEC lower than a predicted value, even when subjected to external pressure due to the operating water depth, or in an annulus flooding event.
The test was conducted in two different phases to separately evaluate the external pressure and annulus condition. The first phase of the test was conducted sequentially at four different levels of external pressure, these being 1, 50, 100 and 150 bar on a dry pipe annulus.
The second phase of the test was carried out after flooding the annulus with water under an external pressure of 165 bar for 72 hours to soak the insulation tapes, which are responsible for the greatest part of the thermal exchange characteristics. After this period, the pipe TEC was measured sequentially at four different levels of external pressure.
By the end of the test it was possible to determine thermal exchange characteristics when the pipe was subjected to environmental conditions representative of actual applications. The relationship between the external pressure and the TEC variation could also be assessed and furthermore, it was possible to evaluate the behaviour of the flexible pipe thermal properties after an annulus flooding event. The test also demonstrated that Wellstream's design methodology properly accounts for the effects that both the external pressure, due to the operating water depth, and the annulus condition has on the pipe's TEC.
SS - Leveraging Technology And Best Practices To Develop The Giant Khurais Field
Authors: Al-Mulhim Waleed Abdulla , Al-Ajmi Fahad Abdullah , Al-Shehab Mahdi Abdulla , Pham Tony Reuben 
Published: July 2009

Abstract
The paper discusses the upstream development of Khurais field, referred to here interchangeably as Khurais Oil Complex, consisting of several fields and reservoirs to a capacity of 1.2 MMBPD of Arabian Light crude. It describes the planning, execution and leveraging of technologies coupled with best industry practices to deliver the target rate while reducing the unit development cost, increasing the well productivities and expanding the reserves base.
At the beginning of the project, a high resolution 3D seismic program was successfully performed to characterize the reservoir structure and geological features. Coupled with vertical-horizontal delineation wells, additional reserves were delineated and added to the development. To reduce the unit development cost, the paper shows that the project utilizes a complex well architecture with combination of maximum reservoir contact (MRC), multi-lateral, and horizontal wells as well as Smart completion, Smart ESP, and passive inflow control device to achieve and sustain the target rates. The development also sets the stage for technology leveraging in the future by drilling wells with large wellbores, allowing flexibility for the next generation complex well architecture while pursuing fit-for-purpose technologies through joint ventures and Saudi Aramco Advance Research Center.
The paper illustrates that the Khurais development is unique not only in terms of its size but also in terms of special technology applications and its complexity with respect to development of multiple fields and reservoirs with proper utilization of many complementing technologies. Through Saudi Aramco best practices, all of these are part of the development plan which utilizes applications of Advanced Mathematical Models in the form of Multi-Objective Function and probabilistic modeling techniques such as Experimental Design and Monte Carlo simulations. The development plan mitigates the development risk and optimizes oil off-take from different reservoirs and areas with respect to well placement, ESP design, depletion rates, injection production ratio, number of injectors and producers, pressure support, sweep efficiency, flood front conformance and oil recovery. The best practices also include real-time geosteering to ensure the horizontal laterals are directed through the best pay possible.
The efforts have paid off as field tests of the producers, at the time the paper was written, show three to five times productivity improvement compared to existing vertical wells in the fields. The development also goes beyond the initial stage of the production as Khurais is the company flagship for I-field technologies in real-time data gathering, transmission and operation remote controlling to enable continuous monitoring and optimization of the field development and reservoir performance.
SS: Arctic: Application of the Newly Adopted IACS Polar Class Rules to Offshore Support Vessels of Small Tonnage
Authors: Springer John A. , Caughlan Sean A.M. , Kristensen Dirk H. , Cronin Daniel D. , Menon Balji C. 
Published: July 2009

Abstract
The Glosten Associates, along with their regulatory partner, the American Bureau of Shipping (ABS), recently completed the design of the 242-foot, ice-strengthened Alaska Region Research Vessel (ARRV) for the University of Alaska Fairbanks (UAF) and the National Science Foundation (NSF). The vessel design is the first reviewed by ABS that meets the structural and mechanical requirements of the new Polar Class Rules developed by the International Association of Classification Societies (IACS). The application of these rules to vessels of smaller tonnage, such as offshore supply vessels (OSVs), maintenance vessels, anchor handling tugs, etc., is of particular interest to designers of vessels that will operate in the newly developing Arctic offshore areas.
The Polar Class Rules represent a major step forward in harmonized, ice-capable, structural design. However, some areas of the rules require further development and cautioned use, particularly for vessels with displacements below 5,000 metric tons1. It is recommended that simultaneous application of the General Ice Class Rules be utilized to identify major areas of impact.
Design consequences resulting from the application of the new IACS Polar Class rules include vessel weight and cost and changes to arrangements, machinery, and operations. These impacts are of great interest to designers and operators of Arctic vessels. This paper summarizes important design guidance for ice-capable offshore vessels and provides guidance on collaborative efforts with ABS, particularly for application to small-tonnage vessels.