bluuebunny/crossref_metadata_2025_split huggingface dataset:
Popeye Project: An Overview
Authors: McLaughlin D.C. , Atford B.J. 
Published: October 2008

Abstract
This paper presents an overview of the Shell Offshore Inc. (S01) Popeye Project, a remote subsea gas development in 2040 ft. of water in the Gulf of Mexico (ref. OTC Papers 8126, 8127, 8128, and 8169 for more technical details). Planning and execution of the Project required a balance throughout between proven methods, cost reduction, requirement for extending technology, and the desire to develop a system which could be used as a stepping stone to future deep water prospects. Popeye was successful]y installed and started up in January 1996. It represents application of an innovative, yet cost-effective, field development system which advanced the state of deep water subsea technology.

Introduction
In 1985, S01 discovered Popeye, a gas field in the Green Canyon Area. A total of nine exploratory wells were drilled, and a four-block unit was approved in 1988. Sol is the operator and has a 37.5% interest. Partners include Mobil Exploration and Producing Co. BP Exploration Inc. (12.5%), and CNG Producing Co (37.5%), who purchased half of S01's share and joined the other Unit participants in 1992.
Joint subsurface and surface development study were initiated in 1989, including consideration of a wide range of compliant structure, floating, and subsea options, processing options, and numbers of wells. With reserves smaller and riskier than originally anticipated, economic evaluations led to a focus by 1990 on satellite subsea development. Subsea feasibility and preliminary design studies addressed technical References and Figures follow paper and cost issues over the next year. However, low product prices made even a subsea solution marginally economic.
S01 formed a Popeye Subsea Team in 199 I (the genesis of current Subsea Systems Team) to tackle the dilemma of how to make Popeye an economically attractive development, while dealing with the severe application requirements of high pressure, deep wsster, and long offset distance. An additional challenge was the desire to utilize technology which could be a springboard for many other, even deeper S01 prospects.
The challenge was met and the development plan approved by the Popeye Partners in March 1993. Key elements of the plan were phased development utilizing fewer, high rate wells, and smaller flowlines and topside facilities. Also, several innovations promised reduced costs and better economics over traditional subsea practices, and represented necessary evolvement for the future. The Popeye Project Team was formed and the project successfully executed by January 1996, Despite difficulties which more than doubled the duration of planned drilling activities, the Project was within original budget and only 3 months later than original schedule.

System Description
The Popeye reserves were deposited in two separate reservoirs within Green Canyon Blocks 72, 73, 116, and 117. The phased development plan includes two Phase 1 subsea wells, directionally drilled from the subsea system location between the reservoirs on Block I 16 to bottom hole locations on Blocks 73 and I I6.
Popeye Project: Completion Riser/Workover Control System
Authors: Guinn R.M. , Parks W.C. , Forster L.D. , Pritchard J.J. 
Published: October 2008

Abstract
In 1993, at the beginning of the Popeye Project, Shell Offshore Inc. (S01) entered into an innovative commercial agreement with Sonsub Inc. (Sonsub) to develop a technological first in the area of completion work over riser systems, Sonsub would design, manufacture and test a new concentric bore Completion Riser/Work over Control System rated for use in water depths of up to 6,000 ft. SOI would then lease the equipment on an as needed basis from Sonsub. This type of relationship proved to be an efficient approach of introducing new technology to the industry and managing the higher costs of deepwater developments.

Introduction
As the industry continues to extend subsea developments to deeper waters with higher pressure reservoirs, the operating limits of the required equipment (such as subsea trees, wellheads, drilling rigs, lay barges, etc.) are being constantly stretched. The commercial issues involved in funding these deepwater developments are also becoming increasingly more complex due to the high costs of the equipment and the ever important length of time to first production.
One of the key equipment components necessary to complete and operate developments is the completion riser and work over control system. This paper will brieflyoutline the methodical approach taken by Sonsub and SOI throughout the initial design, manufacturing and testing.
Stages and it will describe the commercial arrangement between S01 and Sonsub. It will also briefly describe the unique and universal Completion Riser Work over Control System and narrate the results of its first offshore use on the Popeye Project. A summary will follow of the ongoing additions/modifications necessary to meet the world record water depth requirements of S01's Mensa Project.

Background
During the early planning stages of Popeye, SOI had recognized many new technological issues that would have to be solved in order to develop Popeye and its other deepwater prospects in the Gulf of Mexico, Sonsub had also surveyed several offshore operators, including SOI, in regards to a 'Universal' deepwater completion riser and work over control system which would accommodate existing equipment from the various subsea equipment manufacturers. Various types of riser and riser coupling designs, riser spider designs, riser handling methods and various controls equipment packages were reviewed. Operations off shore were discussed in detail and, while several operators expressed a preference for a conventional dual-bore, integral non jacketed riser, most recognized that the existing designs for these types of risers were not adequate for deepwater applications, especially in water depths beyond 3,000 ft. Most operators also acknowledged the suitability of a concentric riser, if a reliable method of accessing both bores was available.
The Unusual Construction Aspects of China's Yacheng 13-1 Gas Pipeline - The World's Second Longest Subsea Pipeline
Authors: Woolgar A.F. , Wilburn J.S. , Zhao X. 
Published: October 2008

ABSTRACT
There are many unusual construction aspects relating to China's Yacheng 13-1 Pipeline. Initially planned as an onshore pipeline it was later to becomeAsia's longest subsea pipeline.
The route chosen resulted in an offshore pipeline requiring many unique andinnovative construct ion techniques as well as unusual pipeline installationconstraints.
The pipeline was installed in two phases. The first phase of 707km was to bethe longest pipeline ever constructed within one lay season and with one layvessel in a continuous programme. Upon completion of the second phase of pipelay works, the world's longest ever subsea pipeline flooding in one run of778kms was to follow.
The Yacheng 13-1 construction requirements for pipelay and post installationworks, including testing and commissioning were extremely demanding.
This paper details how these requirements were met. It covers routeselection constraints, construction techniques utilised and the demandingpigging and pre-commissioning operations performed.

INTRODUCTION
By means of the Yacheng 13- 1 Pipeline, sales quality gas will betransported directly from the offshore facilities via a subsea, 28 inch (711mm) outside diameter (OD) pipeline, 778kms in length, to an onshore facilitynear Hong Kong at Black Point, where it will be treated, metered and delivered. The South China Sea map indicating the pipelines layout is shown in Figure1.
A portion of the gas stream and condensate will be sent via a 14 inch(356mm) OD, subsea pipeline, 91 kms in length directly to a shore facility nearNanshan on Hainan Island, where the natural gas and condensate will beseparated for delivery and storage respectively.
Installation of the 778kms of 28 inch trunkline was awarded to a SaipemSpA/European Marine Contractors Joint Venture (SEJV) in two phases. Phase 1, installation of 707kms, in April 1993, and Phase II, installation of theremaining 71kms of 28 inch including the installation of a 91 km 14 inchpipeline, in April 1994.
The owners of the system are Arco China Inc., China National Offshore OilCorporation (CNOOC) and Kuwait Foreign Petroleum Exploration Company(KUFPEC).
Some Corrosion Concerns for Girth Welds in CRA Clad and Lined Flowlines
Authors: Craig B.D. 
Published: October 2008

Introduction
It is common practice in the petroleum industry to apply two ASTM standard corrosion tests (o corrosion resistant alloys (CRAs) as a means to determine their relative corrosion resistance compared to other alloys and as a quality control method to ensure no manufacturing processes have promised this corrosion resistance. The ASTM G 48 test for pitting resistance in ferric chloride solution is applied in both cases above and the ASTM A 262 Practice E is used in the latter. The A 262 Practice E is also required by API 5LD. Although the G 48 test has generally been successfully applied for ranking the pitting resistance of stainless steel and some nickel base alloys the application of the G 48 and A 262 tests for manufacturing control and for the evaluation of welding procedures has been less than satisfactory, often leadingto conflicting results.
This paper will not attempt to explore all of the myriad problems that have been encountered in applying these two tests but instead on two speed problems that are consistently encountered in evaluating the welding of CRA lined and clad Iine pipe. These two problems are the testing of the inside surface of the liner and red pass of a girth weld to determine the effect of discolouration (heat tint) on the corrosion resistance of the weldment and selective corrosion of the test coupon from the backside (i.e. the side of the cladding or liner on the side nearest the steel) of the test coupon in preference to the root bead side.
In both cases the tests are carried out using the G 48 Method A, generally at 22-25° C for 72 hours.

Standard Test Method and Variations
The standard G 48 and A 262 tests specific that the test specimens be polished to a uniform finish on all surfaces with a 120-grit abrasive paper.
Figure 1 shows how manufacturers and test laboratories often prepare the test coupon. It is obvious that this means of coupon preparation will not test the actual surface properties of the material tier fabrication and furthermore, it is doubtful that the pitting behavior will be affected at all for a coupon of this type regardless of the condition of the inside surface of the clad or liner weldment. Yet it is in keeping with the requirements for coupon preparation according to A 262 and G 48.
For clad and lined pipe welds it is imperative that the back side of the coupon representing the side facing the steel be thoroughly machined to remove iron contaminants that can compromise the test results by producing premature pitting and corrosion on that side before pitting can proceed on the root side of the coupon.
It is more appropriate to leave the root bead and CRA clad or liner inside surface in its original condition in order to determine the behavior of these weldments in service.
Design, Fabrication and Installation of the Mooring System for the Troll B Concrete Oil Production Platform.
Authors: Mørland M. , Frydenlund O. 
Published: October 2008

Abstract
The Troll B Platform is the first purpose built catenary anchored concrete production platform. The project represented a large challenge both to overall project execution and contract strategy as well as within various disciplines. The mooring system represented certainly one of the challenging areas.
In order to safely anchor the platform it was necessary to develop the largest mooring system ever. The design fabrication and finally the installation of the system all represented challenges. The system was, however, installed within planned schedule and budget in July 1995 and has so far functioned according to the expectations.

Introduction
This paper gives a presentation of the development work for the mooring system for the Troll B concrete production platform, see Fig. 1, The presentation includes discussions related to design of the system, based on the given boundary conditions and criteria, as well as fabrication and installation. Technical challenges and considerations to contract strategy in search for the cost optimum system is discussed including aspects related to operational phase, the inspection and maintenance philosophy,
With the size and properties of the platform itself more or less fixed, ref. key in Tableto design a suitable mooring system.
In order to reach a cost effective system it was focused on two overall design principles:Dimensions of the chain and wire should be within certified dimensions (DnV)Installation of the system should be possible from relative conventional marine operation vessels avoiding expensive equipment and vessels.
With the given boundary conditions the mooring system solution is a segment chain/wire rope system with large dimensions, see Table 2 and Table 3.

Design
General. The design of the mooring system for the Troll B platform aimed at an optimisation with respect to both composition of line segments/number of lines and individual segment length and diameter. Fig.2 shows a general view of a mooring line including the positions for the connection and retrieval elements.
The analysis methods described in the following will cover both the mooring lines and special components in the mooring system such as connection and retrieval elements and fait-lead / chain interaction problem.
Design Criteria. The design of the mooring system is governed by statutory requirements as well as functional requirements. The major design requirements are:Safety factors according to NMD (Ref. 1,2).Maximum platform offset of60 meter.All mooring lines to have winches.Passive mooring system, No adjustment of tension during extreme weather conditions,Possibilities of diverless replacement of fairleadsNo retrieval of mooring lines for planned, regular inspection.Installation/Retrieval of mooring lines to be performed by the use of 'conventional' equipment and vessels.Required design life is 25 years
Subsea High Integrity Pressure Protection Systems for high pressure oil and gas developments
Authors: Theobeld M.C. 
Published: October 2008

Abstract
With oil and gas operators now focusing on smaller assets to develop, every opportunity to reduce costs, with due consideration to safety is being carefully considered.
By derating the transportation flowline substantial cost savings are possible. In the past this would not have been allowed for safety reasons, as the flowline was required to be rated to the maximum pressure from the reservoir.
HIPPS is a new subsea technology which allows the high pressure specification flowlines to be safely derated between the manifold and host platform. This is achieved by reliably isolating the high pressure product before the specification break of the lower pressure rated flowline.
The system is designed to failsafe under all operating conditions. Commercial evaluations are given to justifi the technology. The HIPPS control system is described in detail together with summarized reliability data.

Introduction
High Pressure/High Temperature (HP/HT) subsea hydrocarbon developments are now being actively pursued in many Central North Sea areas. These prospects tend not to be large reserves but may have Closed In Tubing Head Pressures (CITHP) in the region of 10,000 psi. This leads to marginal economics of such fields, when the cost of higher specification flowlines are taken into account.
Subsea HIPPS presents an option for justifying HP/HT developments, by allowing high pressure flowlines to be derated to standard pressure flowlines, at considerable overall cost savings.
The HIPPS system provides a reliable failsafe means to protect and isolate the derated flowline at the subsea installation from the high pressure at the wellhead. HIPPS works in parallel with the standard control and safety systems, which would all need to I before HIPPS comes into operation. HIPPS also allows potential cost savings in the topside piping system and a reduction in the platform risk levels by a reduction in system pressure.
The control system for subsea HIPPS is separate from the well control system for the subsea equipment having dedicated power, communication and hydraulic lines, These may be shared in a common umbilical with the production control system, and are integrated into the surface control computer and hydraulic/electrical supply units.
Typical costs savings for a step-out distance of 9 km can be in the region of UK E13 million compared to a fully rated flowline system. This saving may be reduced by selecting a ?no burst' option in order to maximise safety considerations. Based on thorough reliability and risk assessment models Ref. 1 it has been shown the subsea system is extremely safe with the risk of a flowline failure in the order of 1.7E-04 per annum or once per 5900 years.
The control hardware used for subsea HIPPS is based on a thoroughly proven topside, certified fixed logic HIPPS system, which has then been marinised for subsea use. The principle feature for the safety critical controller is its ability for failsafe operation under all modes of failure.
Liuhua 11-1 Development- Phase I Installation
Authors: Sorrel David , Green John D. , Florida Mark J. , Ming Chen , Sheridan John 
Published: October 2008

Abstract
The Liuhua 11-1 Field is situated in 1,020 ft (310 m) of water in the South China Sea. The Liuhua 11-1 Development Project includes a floating production system and floating production, storage and offloading vessel with joining pipelines and risers. The installation occurred in two phases occurring over 12-months to take advantage of two favorable weather seasons.
Phase I, which forms the basis for this paper, was executed during May-July 1995 and includes laying of the moorings for both vessels and the hook-up of the FPS to its moorings. The scope of work and interface management required for installation of 21 mooring legs in this water depth is of particular importance. The vertical lay and tension system designed specifically for this project represented a large financial and engineering investment, The system was designed to lay the eleven mooring legs for the FPS and, ten mooring legs for the FPSO, and to tension the FPSO anchors to 1,323 kips (600 tomes) at the anchor. The system had to handle three sizes of stud link anchor chain and two sizes of bare spiral strand wire rope.
The Phase H installation of February-April 1996 includes connection of the FPSO to its moorings and installation of the three pipelines and their risers.

Introduction
An overview of the Liuhua 11-1 Development Project is presented in OTC 8172 (Ref. 1) and Fig. 1. The development includes a floating production system (FPS), Nanhai 7Tao Zhan, permanently moored over subsea wellheads in 1,020 ft (310 m) of water. Its conversion is detailed in OTC 8187 (Ref. 2). It is a modified semi-submersible drilling rig equipped to provide drilling services and operate the subsea systems. Crude-burning generators on the FPS supply power to an eleetric submersible pump (ESP) in each well. Details of the ESPS are presented in OTC 8176 (Ref. 3).
An overview of the subsea system is presented in OTC 8175 (Ref. 4). Produced well fluids are commingled in a subsea manifold located below the FIN and exported via two 13.5-in. flexible production lines that are linked to the manifold through independent tie-in bases and rigid jumpers. The two production lines together with a 6-in. flexible test line pass along the seabed from the tie-in bases to the floating production, storage and offloading (FPSO) vessel, Nanhai Sheng Li, located approximately 1.8 miles (3000 m) northwest of the FPS (Fig 2). The pipelines are reviewed in OTC 8188 (Ref. 5). They are made of flexible pipe and are connected to dynamic risers supported by discrete buoyancy collars. The pipelines are attached to the FPSO turret in a lazy wave configuration.
Liuhua 11-1 Development-Design and Fabrication Considerations for Nanhai Sheng Li for the FPSO
Authors: Frantz J. Paul , Koster Thomas E. , Yu Liang , Haire William  M. , Shimamura Yoshihide 
Published: October 2008

Abstract
This paper describes the development, design, and fabrication of the crude oil process facilities, and the conversion of an existing tanker for use at the Liuhua 11-1 Field. Over a 16-month period spanning 1994 and 1995, Amoco Orient Petroleum Company, and partners, China Offshore Oil Nanhai East Corporation (CONHE), and Kerr-McGee China Petroleum Ltd., converted a crude oil tanker originally built in 1975 to the Nanhai Sheng Li, the floating production, storage and offloading (FPSO) facility for the Liuhua 11-1 Field, The FPSO will process up to 65,000 BOPD produced from 20 subsea wells located 1.7 miles away. In addition to the processing facilities for produced oil and water, the FPSO has a processed crude oil storage capacity of 715,000 bbls. The ship's propulsion system was removed during the conversion, because the FPSO is permanently moored at site by means of a lo-point, 'soft' mooring. The mooring system was designed to survey the 100-year-retum-period typhoon. Several unique aspects of the ship's conversion process facility, and mooring system design are discussed. Process design aspects include the flexibility to accommodate wide variations in produced water-oil ratio and total volume, the design considerations of the large water and crude processing equipment, vessel motions during operation, and equipment survival during storms. The FPSO design discussion focuses on global hull strength for surviving a 100-year typhoon. Special design requirements for the mooring turret structural integration to the converted tanker are also discussed.

Introduction
The South China Sea hydrocarbon reserves are difficult to develop. The Liuhua 11-1 Field is reasonably typical, but has some unique features:The water depth is approximately 1,020 ft (310m); the location is about 120 miles (200 km) from shore.The metocean environment is such that major storms (typhoons) occur frequently.The site has solitons (internal waves) generated by tidal variations in the Bataan Strait.The crude in the reservoir is parafflnic, asphaltic, and contains both C02 and H2S in moderate quantities.
The primary elements of a successful FPSO are:The shipThe mooring systemThe process facilities
The solution to the FPSO design problem started with the selection of a vessel suitable for service as an FPSO in the design environment. Following this, the mooring system could be designed. The production facilities could be designed to accommodate both the processing requirements and the motions expected of the vessel.
The ultimate requirement for an FPSO is to produce and store crude until it can be off-loaded to a shuttle tanker. In order to do this, it must have a reasonably stable platform and be capable of staying on-station during major storms.