bluuebunny/crossref_metadata_2025_split huggingface dataset:
Operational Experience of FPSO Uisge Germ
Authors: van Voorst O. 
Published: October 2008

ABSTRACT
Blue water was awarded a contract by Amerada Hess Limited to provide production services for the Fife Fieids the North Sea using an FPSO based on a converted tanker. The contract required Blue water to provide the production services from the wellhead to the refinery, The construction period of less than 17 months resulted in first oil in August 1995, Preparing for the operational phase and actual operation of the installation after first oil were also part of the contract. This paper briefly describes the construction phase, the preparatory phase for operations and the first 4.5 months of opera tons up to December 1995. The paper concludes that a wellhead to refinery contract is a feasible and commerciality attractive solution for both oil company and FPSO contractor. The Fife Field could not have been developed if this contracting strategy had not been used, as after depletion of the Fife Field the Usage Germ will be available to be utilized on other fields.

1, Project Description
In March 1994 Blue water Offshore Production System assigned a contract with Amerada Hess Limited to provide a production service from Wellhead to Refinery. Amerada Hess Limited required this service to develop the Fife Field, located in blocks 31/26a, 31/27a, 39/1 and 39/2 on the UK continental shelf in the central North Sea.
In order to fulfill the requirements of the contract Blue wateracquired an existing 99.300 DWT product tanker. We converted the vessel to an FPSO, installed process equipment and mooring systems, and completed the conversion scope in less than 17 months, Contractual payments commenced on first oil production and include a provision for keeping the Installation operational which is related to actual uptime achieved. Furthermore, the full offshore manning as well as an Aberdeen onshore support base are being provided by Blue water during the operational phase.
The contract places all risks related to the reservo r performance with Amerada Hess Limited and includes a minimum duration of 4 years. These issues ensured that Blue water has been able to take a completion risk on the construction phase and an uptime risk on the operational phase. These criteria meant a significant challenge for Blue water's project team due to the fact that this was the first contract of this type. A passively moored FPSO based on an existing tanker had never before been utilized in the North Sea environment,
Due to the contractual arrangements and Blue water's responsibilities towards the UK authorities, Blue water is Safety Case Duty Holder and Operator of the Fixed Offshore Installation while Amerada Hess Limited is the Field License Holder,
Due to limited anticipated producible reserves in the Fife Field and a possibility of other minor producible reservoirs in the same general area, contractual as well as hardware facilities have been foreseen to incorporate the tie-in of future wells to the same installation.
New Data on the Fatigue and Ultimate Limit State of Grouted Tubular Joints
Authors: Morahan D.J. , van Foeken R.J. , Lalani M. , Wardenier J. 
Published: October 2008

Abstract
A Joint industry project (JIP) commenced in 1993'" to develop a design manual for tubular joints which are strengthened or repaired through chord grout-filling. This project has been funded by five oil companies and two regulatory bodies. The project has comprised the conduct of over 150 Stress Concentration Factor (SCF) and ultimate load tests on large scale as-welded and grounded tubular joints. Separate data capture studies, including capture of data on double-skin grout reinforced joints, have been conducted, together with studies on offshore deployment, to ensure that complete chord grout-filling is achieved for all practical scenarios.
The primary reason for carrying out this project has been an industry-wide recognition that chord grout-tilling represents an extremely cost-effective and technically-efficient method to strengthen or repair tubular joints. Further, it has been Recognized that double-skin joints (e.g. pile through leg with anisettes grout-tilled) are often present in structures and the resulting enhanced strength and fatigue characteristics should be exploit+ to permit more efficient new platform designs or better estimation of joint performance for existing installations. Although API RP2A(?' permits the use of grouted joints, little guidance is provided, reflecting the lack of data and information in this area. This project has been carried out to generate a significant amount of new data/information, leading to the creation of a design manual for grouted, joint.

Introduction
Grout-tilling of chord members to enhance the static strength and fatigue endurance of tubular joints is recognized as perhaps the most cost-effective and technically efficient solution available for the strengthening, modification and repair of offshore ions. However, there are significant gaps in the data from the standpoint of present-day potential applications, i.e. the range of geometries, configurations, load cases and conditions for which chord grout-filling may be considered relevant and appropriate. Therefore, to generate new data applicable to appropriate strengthening or repair events, a test matrix was selected on the basis of likely strengthening and/or repair scenarios. To enable the measurement of Strain Concentration Factors (SNCFS) for all load types for each specimen, a specialized test rig was designed to facilitate loading in the four loading modes. A sophisticated test rig was designed to enable rapid execution of test measurements in all loading conditions without the need to remove or re-orientate each specimen.

Review of Existing Guidance
The provisions of major design codes on any aspect of grouted joints are limited. API RP2AC', HSE Guidance Notes('), NPD'4' and DNV(s' all state that capacity may be established by testing and/rrr analytical methods. The HSE Gui&nce Notes specifically allows the use of grout filling for joints on existing installations.
Operating Procedures - Preliminary Results of a Safety and Environmental Management Program (SEMP) Case Study Sponsored by the DOE and MMS
Authors: Bresler Richard A. , Tibbetts Owen D. , Von Antz Gerald 
Published: October 2008

Abstract
On June30, 1994, the MMS published a Federal Register notice requesting that industry voluntarily adopt API RP 75 (SEMP). Under the SEMP program, offshore producers would be responsible for identifying potential hazards in the design, construction and operation of drilling and production platforms and developing specific approaches to reduce the occurrence of accidents.
Many smaller and mid-size independent producers have raised questions over the costs and methods for implementing SEMP. The DOE and MMS determined that a carefully documented case study would answer many of the producers' questions. The results of the study would be oriented specifically to small- and mid-size companies, so independent producers would be much more willing to invest the time and resources to adapt theRP 75 procedures to their own operations. As a result, the DOE and MMS have entered into a 30-month study with Taylor Energy Company (TEC) and Paragon Engineering Services (Paragon) to develop a Safety and Environmental Management Plan (SEMP). This program is intended to demonstrate how small- to mid-size companies can effectively and inexpensively develop a SEMP in accordance with API RP 75.
This paper will discuss the preliminary findings associated with the Taylor Energy Company/DOE SEMP case study. Specifically, the development of operating procedures which meet the intent and spirit of SEMP without the traditional high cost typically associated with 'engineered operations manuals' will be discuss.

Introduction
Section 5 of SEMP is titled 'Operating Procedures' and is written almost identically to the Operating Procedures section in API 750, Management of Process Hazards. This fact is important to understand because API 750 was developed for refineries, petrochemical operations, and major onshore processing facilities. API 750 is not directly applicable to most OCS platforms. Since the goal of this SEMP project is to develop a 'cost-effective' method for small and mid-sized independents, this paper will provide thoughts on how to achieve the 'spirit' of SEMP without incurring the paperwork burdens of a complex facility operation.

Overview of Section 5- SEMP Operating Procedure
Section 5.2.a requires that the written procedures include the job title and reporting relationship of the person or persons responsible for each of the facility's operating areas.
This goal can be accomplished with a simple organization chart for moat small and mid-sized independents. In many cases, such a chart already exists. Section 5.2.a offers no pertinent benefit to the small independent because, in the majority of cases, only one operator (and a helper or roustabout) is responsible for an entire platform and perhaps one or more unmanned facilities as well. The small independents' organizational structure is usually very flat, unlike that of a large organization typically associated with a refinery or petrochemical complex.
DP-PS: A Safety Program for DP Operations
Authors: Cordeiro André , Pashoalin Roberto , Fartes Evandro 
Published: October 2008

Abstract
As PETROBRAS develops its deepwater projects. more and more DP units are used on different applications like drilling. completion, intervention and pipeline handling, The increasing complexity of the operations has been considered in a program entitled 'DP-PS' (Safety Program For Dynamic Positioning Operations) in order to minimize the risks of failures which could lead to serious accidents on subsea and surface installations as well as to the DP vessels. This paper briefly presents the DP-PS. consisted of a group of related projects considering different aspects of DP operations, like: Vessels Incidents Databank, Emergency Disconnection Procedures. Risk Comparison, DGPS (Differential Global Positioning System) application, Well Control Equipment and Standard Procedures. Testing Programs and Guidelines for DP Operations. The high number of DP contractors operating in Brazil and the atmosphere of cooperation in which the program has been developed was a key factor for its success, As a result, the number of DP incidents has remarkably decrease.

Introduction
Since it is a quite new activity all over the world there are several concerns related to production in deepwater, ranging from tedmology and related costs to lack of adequate material and equipment resourees, Among them, a key point is the must of conducting the operations un&r a reasonable safety level. This issue turned to be more important considering the characteristics of DP (Dynmnic Positioning) rigs and its application on development tasks which should occur inside restricted areas, different from normally isolated exploration wells.
In December 84 the first program in Campos Basin. DP unit started an exploratory Since then, the DP fleet has increased and for next year eleven units are planned to be simultaneously working. mainly involved on the development plan of Marlin and other deepwater fields.
Some particular initiatives have been taken since that beginning, Among these initiatives there was a particular care about disconnection procedures and well control policies.
Anticipating the new development phase, PETROBRAS established an integrated program which should verify the main safety aspects related to DP equipment application named DP-PS (In Portuguese: DP- Programa de Seguranca).

Program build-up
In 1992, a group of DP rigs arrived in Campos Basin, stepping up to five the number of DP contractors. Brazilian waters became a unique play where so many DP rigs were operating at the same time, bringing the possibility of speeding up the development of operational know-how.
A group of experienced skills in deepwater operations were put together to raise ideas that could enhance safety, A brainstorm session took place and. in sequence, some principles were applied to the proposed ideas: Firstly, the program should focus on important matters from the point of view of the man on board the unit.
Construction of a Large Underwater Acoustic Array
Authors: Zueck Robert F. , Brackett Ron L. , Smith Anthony P. , Shields David R. 
Published: October 2008

Abstract
Recently installed in Lake Penal Oreille, Idaho, the acoustic arrays for the Intermediate Scale Measurement System involved an extensive effort in construction planning, Composed of many inter-connected structural lines, electrical cables, anchors, buoys, sheaves, hydrophones and acoustic transducers, the array was assembled underwater one component at a time. Because each component had to be placed in a precise position, the installation effort required a technically advanced positioning system, a specially built project barge, and unique deployment methods. Many of these installation procedures are applicable to installation of other types of deep-water structures.

Project Background
Situated in Lake Penal Oreille, Idaho, the Intermediate Scale Measurement System (ISMS) provides high quality measurements of the structural acoustic response of large-scale submarine models in a controlled environment 1. Fig. 1 shows the Near-Field Array (NFA) of the ISMS. The NFA consists of the following system components, located in the 1,200-feet (366- meters) deep lake:Transmit Array (TA): A vertical plane of projectors for transmitting an acoustic signal.Target Model Haul-Down (TMH); A mechanism for handling a buoyant submarine model.Receive Array (RA): A horizontal ring of hydrophones for measuring the acoustic signature.l N-Array (NA): A small set of hydrophones for measuring the incident acoustic signal.
All acoustic components and the submarine model are in a horizontal plane at approximately mid-depth in the lake. The TA projectors hang below a rigid buoyant truss structure, Two anchor lines at each end of the TA truss hold the truss approximately 64 feet (20 meters) below the lake surface. Located on shore approximately 2.5 miles (4 km) from the NFA site, winches haul the buoyant submarine model underwater. A network of underwater electrical and fiber-optic cables connects the acoustic arrays to shore. Of the NFA components, the RA provided the most challenging installation effort. Thus in this paper, we shall focus on the RA structure.
Receive Array (RA). The receive array consists of 12 segments of hydrophones, totaling 158 hydrophones. When connected end to end, these segments form an oblong ring surrounding the submarine model. The longest hydrophone segment is 282 feet (86 meters) long. A structural node at each end of each segment holds each hydrophone segment in place. Each node is 602 feet (183 meters) above the lake bottom. Electrical cables carry acoustic information from each end of each RA segment to the TMH and then on to shore.
A buoy near the water surface and three anchors at the lake bottom hold each node in place. Each node buoy is a 6-foot (1.8-meter) diameter syntactic foam sphere. Each anchor is an 8-foot (2.4-meter) square steel 'cookie-cutter,' A 0.5-inch (1 .25- cm) diameter parallel-fiber aramid (Kevlar) line connects each anchor to each node. End sections of wire rope provide for precise final adjustments in length given as-installed anchor locations.
Phillips Seastar Project: A Teamwork Approach
Authors: Upchurch John L. 
Published: October 2008

Abstract
In order to better meet the challenges associated with downsizing and because of the ongoing need to control costs and accelerate project development many companies are trying new and different strategies in managing projects. For the Sea star Project, Phillips adopted a total team approach. The goal of this approach was to develop a win/win attitude for all of the personnel (Phillips, Engineering Contractor and Equipment Vendors) involved in the project. By bringing all the personnel together and focusing on project success it wasthought that costs could be better controlled and that the development schedule could be accelerated.

Project Overview
The Sea star Project is a two well subsea development located in Garden Banks Blocks 70 & 71 approximately 120 miles south of Cameron Louisiana (figure 1). The water depth at the well location is approximately 750 feet and the blocks arc 12- 14 miles from the closest existing platform. These blocks were originally leased by Phillips Petroleum Company, ct al. in 1987. Phillips was not the original operator of these blocks. Two wells were initially drilled (one in each block) but, the reserves were not sufficient to justify development. Phillips took over operator ship in 1992 and drilled Garden Banks Block 7 I #2, which discovered 349 feet of net gas pay in April 1993. Following a successful drill stem test on GB 71 #2 drilling was started on an appraisal well and work beganon a feasibility study to define development options.

Phillips Philosophy/Goals
Phillips project development goal is a safe, customer driven, timely and cost effective development. For various reasons, Phillips had made the strategic decision to not maintain an in house staff of technical project personnel and it was realized that an outside engineering company would need to be contracted for the project.
Phillips was an early pioneer in subsea development and had installed one of the first piloted control systems offshore California, However, Phillips had not installed a domestic subsea development since California (1980) and all of Phillips' international subsea work was in shallower water depths and had shorter offsets. None of Phillips active offshore platform developments were in water this deep either. Lack of experience and the need to control costs resulted in a desire to use as much proven technology as possible in the development. It was felt that the industry had proven technology for these water depths and focusing on proven technology would reduce the project risk; technical, schedule and cost.

Feasibility
A feasibility team was established in April 1993, immediately following the testing of Garden Banks 71 #2, with personnel from Operations and from the Corporate Engineering staff. The purpose of this phase of the project was to identify and review development options so that a final decision on development could be made when Garden Banks 70 #2 was completed.
Experience with Flexible Pipe in Sour Service Environment : A Case Study (The Arabian Gulf)
Authors: Al-Maslamani Moh'd J. 
Published: October 2008

Abstract
The suitability of a flexible pipe was evaluated on a trial basis for a lift gas line in a sour oil field in the State of Qatar, in the Arabian Gulf. Flexible pipes have been successfully used in the oil and gas industries for transportation of methanol, benzene and gas condensates in wet sweet environment at temperatures of Uplo 80°C. However, there is little or no information available as to its corrosion resistance in sour service wells containing 6% co2with 3% mole H2S and at moderate temperatures. The present experience with a flexible pipe in the gas field of Qatar has shown that under sour service conditions, the Iayered, composite material can suffer severe degradation leading to failure. A detailed inspection and failure analysis of the flexible pipe forms the basis of this paper, The failure demonstrates the significant effects of stress Ievel, environmental aggressiveness, and Iocalised hard zones in promoting Sulphide Stress Cracking (SSC). Permeability of the sour gas through the composite layer of the flexible pipe resulted in varying degree of sulphide attack and hydrogen embrittlement depending on the susceptibility of the multi Iayeredmaterial.

Introduction
The application of flexible pipe for pipelines and risers is increasing due 10its low installation costs. Flexible pipes have been used123 in oil and water service with considerable rneasure of success. These pipes have been found suitable for transportation of water and methanol intermittently, and gas condensate containing abut 40% 0bcflane in the Wet sweet gas at temperatures of up to 80°C. However, there are limited operating experience available in the oil and gas industry with flexible pipes in both wet gas and sour gas services. The structure of the flexible pipe is illustrated schematically in Figure (l), and the various layers present are :Polyethylene (HOPE) external sheathFabric tapeCrosswound first armourFlat spiral second armoutZeta spiral reinforcementIntermediate pressure Rilsan sheathIntcdoeked stainless steel type 316L carcass
The pressure and tensile armour wires are encapsulated between an outer (polyethane sheath) and an inner (Rilsan sheath) polymer barrier. The armour wires should remain unaffected by both sea water and the gases (CH H2Sand C02) as long as the polymer barriers are intact. A typical performance characteristic of the flexible pipe is the permeability to gases. All polymers are to some extent permcable4 to gases, and the amount of permeation depends on the type of gas and the type of polymer. In flexible pipe, permeability may allow gases to pass through the primary fluid or gas-containing layer and build-up in the interplay region. The diffusion of corrosive gases into the annulus means that the armour wires are exposed to a corrosive environment.
Problems of Deep Drilling in Abnormally Pressured Zones of the Kara Sea Continental Shelf
Authors: Simonov V.I. 
Published: October 2008

Abstract
There are discussed results of drilling operations in shelf hydrocarbonareas of the Far North of Tyumen Region (Kharassaveiskaya, Bovanenkovskaya andKrusenshternskaya ones) and on the Bely Island. The author describes equipmentand technologies used, problems arising in the process of operations andpossible ways of solving them. Application of the results discussed in thereport seems rather attractive in connection with possible realization of jointprojects on development of the mentioned areas. Thus, company Amoco Eurasiaplans to participate in development of Bovanenkovskoye and Novoportovskoyefields. Well planning for Amoco has been done by specialists ofZapSibBurNIPI.
Experience of Russian drilling companies in Yamal area (Far North of TyumenRegion) has proved that well planning for shelf areas requires specialattention as drilling-in both overpressured zones (Bovanenkovskoye field) andunderpressured ones (Novoportovskoye field) is done actually in balance. Thereare investigated reasons for such drilling problems as kicks and lostcirculation. Taking them into consideration will help to decrease considerablythe cost of well drilling in shelf areas.

Introduction
Field studies in the process of drilling on the Kara Sea shore revealed thatin deep wells lost circulation takes place first of all problems and later, asthe result of considerable mud losses and fast decrease of dynamic level in thehole, it turns into oil or gas kick. It appeared that because of revealedregularities in the geological section of most areas studied it is impossibleto avoid problems just controlling mud density according to preliminary workedout scheme. Due to lack of ideas about the reasons for drilling problems andconsiderable divergence between theoretical data and actual results of drillingin abnormally pressured zones there appeared a necessity to perform on-siteexperiments and to develop on the basis of a rheological model a new theory offracture appearing and closing in rock while drilling which should take intoaccount effect of different stresses in a hydrodynamic system.