bluuebunny/crossref_metadata_2025_split huggingface dataset:
Foinaven: A Basis of Design for Development Wells
Authors: Howes D. , Cropper M.J. , Prise G.J. 
Published: October 2008

Abstract
The paper provides the Well Engineer/Manager with an overview of the basis of design for Foinaven wells; outlines the contracting strategy adopted forWell Construction; presents a summarized operational programme; and highlights some of the early lessons learned on this fast-track frontierproject.

Introduction
The opening of the West of Shetland oil province presents a new range of challenges and opportunities from those typically encountered in the North Sea. There are a new set of operational problems which have to be faced in a harsh and remote area.
The Foinaven field is located on the flank of the Faroe-Shetland trough approximately 180 km west of the Shetland islands, and 220 km north of the Scottishmainland (see figure I). The field is situated in deep water - the 500m bathymetric contour runs through the field - and in an exposed position on the North Eastern rim of the Atlantic Ocean.
The discovery well on the field, 204/24a-2, was drilled by the Ocean Alliance, in the autumn of 1992. Reservoir evaluation and appraisal was rapid with 6 further wells drilled and an Extended Well Test performed in 1994. As a result of this highly successful production test, project sanction was achieved in October 1994 and development drilling commenced on 9th November 1994.
The objectives of this paper are to provide the Well Engineer/Manager with an overview of the basis ofdesign for Foinaven wells; to outline the contracting strategy adopted for Well Construct ion; to present a summarized operational programme; and to highlight some of the early lessons learned on this fast-track frontier project.

Development Overview
It is planned to develop the field with clusters of subsea production wells producing to and controlled from a Floating Production Storage and Off-loading Vessel (FPSO).
The reservoir measures approximately 16 km by 10 km, and comprises a series of channel sands, running in an east-west direction. The reservoir, which lies 1650 m below seabed, has 3 distinct sand packages which are separated by mudstones. The oil is heavy compared to North Sea crudes (26 ° API), saturated, and sweet. Reservoir pressure is normal (3190 psi 2158 m TVDSS); reservoir temperature is 138 °F. The field has a gas cap, and is attached to an aquifer. Because the individual sand packages are thin (typically 50m TVD), and because the reservoir fluids are of low energy, all production wells arehorizontal, with over 1000 m net producing sand. me net to gross ratio is typically in the region of 60% (Cowper et al., 1995).
The field is extensive in area, and quite shallow. It is being developed from two drilling centres (with a remote gas disposal well), and requires extended reach drilling (ERD) techniques with wells typically having a horizontal displacement to vertical depth ratio of 2.25:1.
The Influence of the Bow Shape of FPSOS on Drift Forces and Green Water
Authors: Buchner Bas 
Published: October 2008

Abstract
In this paper the influence of the bow shape of FPSOS on drift forces and green water loading is studied. Use is made of the results of model tests and diffraction calculations for three different bow shapes: a traditional tanker bow, a sharp alternative bow without flare and the same alternative bow with a significant flare above the still waterline. For the sharper alternative bows the mean wave drift forces and low frequency drift forces seem to be smaller than for a traditional bow. Due to the fact that the wave frequency motions with the alternative bows are larger, it is not clear yet whether the total mooring line loads for this type of vessels will be lower. For the alternative bows the relative motions around the bow are larger. This results in more water on the deck with the alternative bows than with a traditional bow. Also the impact pressures are significantly higher. The results presented in this paper make clear that it is not sensible to optimize a bow of an FPSO on one aspect only,

Introduction
With the trend to bring FPSOS to increasingly harsh environments, the problem of solid green water on the bow becomes an important design aspect. This green water cm cause serious damage to the sensitive equipment or superstructure at the bow, as was experienced with operating FPSOS at the North Sea. There are two ways to cope with this problem: protecting critical structures against green water loading or minimizing the occurrence of green water occurrence and its loading. The achieve the last, the bow shape and bow height of the FPSO can be optimized. Especially for new build FPSOS this is an option, but also for existing tankers optimization are possible].
The effect of the bow shape on the occurrence of green water has been a point of discussion for Naval Architects over a large number of years. Some authors report a decrease in deck wetness when a significant flare is applied3 for traditional ships, whereas others find an increase in deck wetness4 with flare. In Ref. 1 the author presented tests with a traditional FPSO tanker with and without bow flare. It was found that for this particular bow the relative motions increase when flare is applied, whereas the water height on the deck decreases slightly. However, it was concluded at that time that this is not per definition a general trend.
It should also be noted that it is not sensible to optimize the bow shape of FPSOS solely on green water loading. The bow shape can FPSOs effect other aspects of the design, like the (low frequency) drift forces on the ship and the related mooring forces. A bow optimized on green water loading, can may be increase the mooring forces and vice versa. The effect of the bow shape on the added resistance of sailing ships in waves has been studied by Blok5. Detailed published studies on the subject of drift force dependency on the bow shape of moored FPSOS are not known to the author at present.
The Concerns and Benefits of Standardization on the Heidrun Subsea Water Injection System
Authors: Pugh R.R. , Turner R.R. 
Published: October 2008

Abstract
Ms paper describes the process of standarzing the Heidrun Sub sea water injection system. The layout, basis of design and equipment utilized are presented, along with exploring the benefits and concerns of adopting a standard sub sea system. Realized by this approach were: the interchangeability of equipment between Heidrun and other licenses, the lowering of development costs, the capturing of key-lemmings and the sharing of resources. By identifying and weighing the benefits versus the concerns, standardization can be successfully utilized between petroleum companies with different project parameters, thus saving significant costs for all parties.

Introduction
There are marry benefits, concerns, and reward associated with standardizing a sub sea system. In the earlier stages of the Heidrun development, several sub sea concepts were evacuated, ranging from individual water injection wells tied back to the Tension Leg Platform (TLP), to multiple-well sub sea templates.
It was recognized that substantial savings and synergies could be achieved if the Heidrun Project chose art economically viable development concept which fit into Statoil's long-term strategy for sub sea developments (being that Statoil would take over operator ship of the Heidrun field at first-oil). After evaluation, it was decided that the Heidrun Sub sea Water injections System would be modeled after Statoil's Stratford Satellite Project (SSP) design.
However, there were problems. Operating parameters specific to Heidrun, would have to be met. Agreements had to be reached on the use of the existing specialized sub sea tools which were not part of the Heidrun partnership. Finally, capturing the knowledge already hard-won by SSP had to be integrated into Heidrun. This paper describes the Heidrun sub sea water injections system specifics, and shows the process of working through concerns and thereby realizing the benefits of standardization.

Heidrun Subsea Water injection System Description
The Heidrun Field is roughly 10 km long and 6 km wide (figure 1). It is situated on the mid-Norwegian Continental Shelf in an area known as Haltenbanken, 175 km from the Norwegian coast in Production Licenses 095 and 124. The field lies pre-dormis within Block 6507/7 with an eastern extension into Block 6507/8, and in water depths ranging from 310 to 348 meters.
The major reservoirs consist of the Fangst Group, the Upper and Lower Elfie, and the Are Formations, all of Jurassic age. During the planning stages, it was recognized that perimeter sub sea water injection wells would be required to reach the water column in some of the existing fault blocks. The option of extended reach wells from the TLP was explored, but was rejected due to technical difficulties and associated costs. Six water injection we] Is were deemed necessary for optimum, initial water injection and were planned to be drilled from two seabed locations.
The Heidrun Field: TLP Global Performance and Hydrodynamics
Authors: Matten R.B. , Strømsem K.C. , Lassabliere J. , Vogel H. 
Published: October 2008

Abstract
Heidrun, the first deep draft concrete TLP, was installed in July 1995 in a water depth of 345m on the Haltenbank of the Norwegian Continental Shelf. The TLP has a displacement of 290610 tomes and the hull was designed to support a total topsides weight of 64980 tomes on Module Support Beams (MSBS) weighing 18550 tonnes.
The TLP is a marine and structural system with complex interaction between the hull, topsides and the mooring system. This paper describe a the basis for the sizing of the hull and tether system. Key issues addressed include weight control, stability during installation, tether system loads and constraints from fabrication and installation. The relative merits of the use of concrete rather than steel for the hull construction are discussed from a hydrodynamic perspective.
Hydrodynamic model testing was used to resolve many critical design issues, including 'ringing' which has had significant consequences for other deep water offshore platforms. New criteria were established for tether pretension.
The Operational Expense of TLP Marine Control has been minimized by provision of the Marine Control and Data Acquisition system (MCDA), which is used for in-service control of tether tension and for acquisition of key environmental and performance data. Continuity of weight control during Engineering, Construction, Installation and Operation was successfully implemented. TLP Performance data is presented in sea states up to 10.5m significant.
Evaluation' by the Conoco Project Team of TLP performance, on-board training of Operators and provision of an automatic system for continuous shore-base monitoring of marine performance facilitated the timely handover of responsibility for TLP Marine Control to Statoil Operations.

Introduction
Early conceptual studies [1, 2] identified several advantages of the concrete hull which were key in concept selection. These include elimination of fatigue concerns at complex node intersections, high distance to impact loads, relatively simple and faster construction, low sensitivity to increases in topside a weight and low tether design loads.
Preliminary Engineering Contracts were awarded to two competing Contractors in February 1991 for development of a concrete hull TLP for the Heidrun Field Development. The Engineering, Procurement, Construction and Installation (EPCI) contract was awarded to Norwegian Contractors (NC) in December91. Following wind tunnel testing of the topsides in November91, the NC concept was model tested in January 1992 in order to accommodate the design freeze scheduled for the end of March 92.
Unexpectedly high loads were measured in the tether system due to 'ringing', the term given to the global vibration of the TLP at it a natural period in pitch and roll, coined during the model testing of the Hutton TLP in 1979-80. Ringing was previously considered for steel TLPs to be a minor load effect and its cause had never been clearly identified.
The Heidrun Field - Heidrun TLP Tether System
Authors: Hornung M.R. , Hanna S.Y. , Hannus H. , Rowan D. 
Published: October 2008

ABSTRACT
The Heidrun TLP was installed in July, 1995. The tether system was developed to meet the following requirements preinstall the tether strings before platform installation; commission the tether tension monitoring system before platform tow to field; lock-off on all sixteen tethers simultaneously 50-year platform design life inspection, maintenance, and repair capability over the operating life. The system and component designs, operations trials, and experience to date are summarized.

INTRODUCTION
This paper presents a brief description of the Heidrun tether system, which anchors the platform to the seabed foundations. The overall system is shown in Figure 1. A description of thefunctional requirements for both present and installation phases provides the background for the system configuration.
The global platform response gives the performance requirements. As the Heidrun platform differs considerably from previous tension leg platforms, a number of challenges had to be faced. The main ones related to loads, installation and schedule.
The tether system was divided into component assemblies or packages, bawd on logical interfaces and contractor capabilities. An outline of the assembled unit is given in Figure 2. The features of the component assemblies are described next. The main packages are the bottom connector assembly, the flex element, the tether string, the top connector assembly, the installation equipment, the tether tension monitoring system and the tether inspection system.
As part of the system design, the main components were subject to prototype testing. In addition, trials of the inspection maintenance, and repair equipment were performed onboard the platform before the tow to field. Further, the installation equipment was tested and the full installation crew was trained on board before low.
The paper is concluded by the main experiences from implementing the chosen solutions.

SYSTEM CONFIGURATION
From experience gained during earlier tether system work, it was apparent that development of the Heidrun tether system should simultaneously consider both temporary and permanent phases when defining system requirements. Thus, a systematic approach was applied which brought together consideration of in-place operation, installation, fabrication, and integration inter facing with the platform's substructure and foundations.
During the course of preliminary engineering in 1991, the Heidrun tether system's overall configuration was therefore development in parallel with the development of the marine operations required for installation of the tethers and platform. From the beginning of this work it had been assumed that thetethers would be of single-piece, neutrally-buoyant design. Other options such as the use of connectors and welding in-situ were investigated but the single-piece welded system was the most economic concept for this environment.
Rocky Flowline Project - The Gulf of Mexico's First Reeled Pipe-in-Pipe
Authors: Hoose J.W. , Schneider D.R. , Cook E.L. 
Published: October 2008

Abstract
The paper reviews the Rocky Flowline project from preliminary design through detail design, testing, fabrication, and installation, The emphasis of the paper is on the issues involved with deep water insulated flowlines, with special emphasis on fabricating and reeling insulated pipe-in-pipe flowlirres. The paper highlights the design and installation of 21,000 ft of dual insulated 3-inch inside 6-inch flowlines in water depths up to 1785 feet. The paper and project is of significance to those in the industry involved in deep water oil development and the transportation of waxy crudes.

Project Overview
The Rocky Prospect is located in 1785 f=t of water in Green Canyon Block 110 (Figure 1). It is being developed by a single subsea oil well tied back approximately four miles to the Green Canyon 65A (Bullwinkle) platform by two nominal three inchflowlines of pipe-in-pipe construction till-rated for the design shut in tubing pressure of 7200 psig. A strong water chive is expected resulting in production rates of up to 8000 BOPD
The well was drilled, cased and temporarily abandoned in Second Quarter 1995. The flowlines were installed in July 1995 by the reeling method. The flowlines were laid horn GC 65A towards the well where they were terminated on a common sled which was placed a short distance from the wellhead, Completion of the well and the installation of the subsea hardware began in December 1995 and first production occurred in January 1996. Flexible pipe jumpers installed by the completion rig connect the subsea tree to the sled.
The subsea tree is an API 10,000 psi design with a single master valve and a piloted hydraulic control system. A thermoplastic hose umbilical connects the well to a hydraulic control panel located on GC 65A. The umbilical includes conduits for the hydraulic control functions and chemical injection, as well as electrical cables for pressured temperature date transmission back to GC 65A. Facilities are provided to allow paraffin inhibitor to be injected downhole and methanol to be injected at the tree if required for hydrate inhibition.
The dual flowlines allow periodic round trip pigging from the platform via a pigging loop on the Gee. The well can be configured to flow through either one or both of the flowlines, A surface choke at GC 65A is used to control the flow rate. In the event of an extended shutdown, the flowlines are displaced with dead oil to prevent hydrate formation.

Preliminary Design
In order to mitigate paraffin and hydrate concerns it was deem necessary to minimize heat loss in the flowlines keeping the platform arrival temperature above the anticipated crude oil cloud point of 90 degrees Fahrenheit. Preliminary analysis indicated that externally applied insulations could not meet this design criteria. Flowline bundle and pipe-in-pipe designs each were capable of meeting the heat retention criteria and were both investigated further.
Seismic Hazard Evaluation of the Oman India Pipeline
Authors: Campbell K.W. , Thenhaus P.C. , Mullee J.E. , Preston R. 
Published: October 2008

Abstract
The proposed Oman India pipeline will traverse approximately 1135 km of the northern Arabian Sea floor and adjacent continental shelves at depths of over 3 km on its route from Ra's al Jifan, Oman, to Rapar Gadhwali, India. The western part of the route crosses active faults that form the transform boundary between the Arabian and Indian tectonic plates. The eastern terminus of the route lies in the vicinity of the great (M - 8) 1819 Kutch, India, earthquake. A probabilistic seismic hazard analysis was used to estimate the values of peak ground acceleration (PGA) with return periods of 200, 500 and 1000 years at selected locations along the pipeline route and the submarine Indus Canyon?a possible source oflarge turbidity flows. The results defined that the ground shaking hazard along the pipeline route and Indus Canyon for evaluation of risks to the pipeline from potential earthquake induced geologic hazards such as liquefaction, slope instability, and turbidity flows.

Introduction
The Oman India pipeline is the most technically challenging offshore pipeline project in history. Its inaccessibility makes it essential that potential earthquake hazards such as ground shaking, slope instability, liquefaction, and turbidity flows be Bthoroughly understood and mitigated. This study addresses the ground-shaking hazard. The results of this study will be used by others to address the geologic hazards.
Pipeline Route. The proposed submarine pipeline originates at Ra's al Jifan on the east coast of Oman and terminates at Rapar Gadhwali on the northern coast of the Gulf of Kutch, India (Fig. I). The total length of the pipeline route is approximately 1135 km. Offshore Ra's al Jifan, the pipeline route traverses the relatively narrow Omani continental shelf, crossing the Siquirah fault and descending the steep continental slope to a depth of 800 m. The route then proceeds in a southeasterly direction towards the Owen Fracture Zone- Murray Ridge Complex, descending to a depth of more than 3000 m. Within this complex, the pipeline route crosses the northern segment of the Owen Fracture Zone and the southern extension of the Dalrymple Trough.
From the Murray Ridge Complex, the route continues in an easterly direction and descends onto the Arabian Sea Abyssal Plain and the Indus Fan where it achieves a maximum depth of 3500 m. Several hundred kilometers from the India coast near 66'E, the route turns towards the northeast, crossing several major submarine channels that are incised into the Indus Fan. As it approaches the coast of India, the pipeline route undergoes a steep rise to a depth of 200 m and traverses 140 km of gently sloping continental shelf to its terminus at Rapar Gadhwali.

Seismic Hazard Analysis Methodology
Ground-shaking hazard was quantified of peak ground acceleration (PGA). Specific seismic design criteria have not been established for the pipeline. In lieu of specified criteria, values of PGA were estimated for return periods of 200, 500 and 1000 years.
Fatigue of Mooring Chain in Air and Water - Results and Analysis
Authors: Stiff John J. , Smith David W. , Casey Neil F. 
Published: October 2008

Abstract
The paper will present the results of the joint industry study into the fatigue resistance of large diameter anchor chain', and discuss the interpretation of the results. The study represents the largest body of well documented corrosion fatigue tests on a variety of different chain grades and sizes. The analysis & the results use the available fatigue data, including the life of tested but un-failed Iinks, to determine suitable fatigue curves for mooring lines of different lengths. Many of the findings were to be expected, based on past data, but there were some surprises with respect to chain grade. Fracture surface examination indicate that the fatigue cracks had propagated across a large percentage of the section prior to final tire. Post test inspection of un-failed links indicate that many cracks had initiated prior to failure.

Introduction
In 1989 Noble, Denton and Associates, Inc. (NDAI) launched a joint industry study into the fatigue of mooring anchor chain. At the time there was very little fatigue data available, and almost no consistent sets of data comparing different parametersat realistic mean loads and dynamic load ranges.
The main study reached completion in December 1992 when National Engineering Laboratory (N EL) completed as much of the test program as they could within the budget provided.
The program consisted of sets of air and water fatigue tests. All of the air tests, and two of the corrosion tests were carried out in a 'Pre-Test' program. This was set up to determine priorities for the main test program performed at O.7Hz, except for two performed at 0.2 Hz. The main test The sea water tests were benchmark tests that were program entailed only sea water tests. In total, there were seven air tests and nine sea water tests, producing 49 fatigue failures and 66 test run out
It appeared from the last test of the main test program that there was a disproportionately low life for the 4' K4, in water, which had not been expected based on the results of the pretest program. In the pre-test program, conducted in air, it appeared that it would be reasonable to plot the fatigue life of K4 on the same Iine as ORQ chain, but using K4 break in strength. (This is contrary to what is said in API RP 2FP12, which was, it was assumed, being conservative because of a lack of data.) By contrast, the corrosion fatigue test results from the main program suggest that the fatigue life of K4 is at the 'lower end' when it is plotted with respect to ORQ chain breaking strength. For this reason, it was suggested that additional tests be run on 3' and 4' K4 chain, The extension study entailed a further four corrosion fatigue tests.