bluuebunny/crossref_metadata_2025_split huggingface dataset:
Twenty-seven Year Old Jack-up Converted to a MOPU in 122 Days
Authors: Childers Mark A. , Spottswood Rick , Lovaas Wes 
Published: October 2008

Abstract
The conversion of the 27-year-old jack up MODU Gulftide to a Mobile Offshore Production Unit (MOPU) was accomplished on a VERY fast-track schedule at a U. S. Gulf Coast shipyard. The reactivation of the long-term stacked rig, its conversion, mobilization to West Africa and installation were accomplished in a period of less than six months during the spring and summer of 1995. This paper outlines the requirements for this type of conversion process, reviews the permitting, classification, flagging and certification involved, and describes the principal activities and work scope in detail associated with the conversion project, dry-tow mobilization and installation. The general approaches taken to this conversion and the project management techniques applied to it proved highly successful and are suitable for application to a wide range of similar projects.

Introduction And Objective
The Block CI- 11 Field 60 miles west of Abidjan, Ivory Coast, and 8.5 miles offshore first yielded an oil discovery in 1980 that by itself was uneconomic. In December 1993 UMC Petroleum Corp. discovered gas in this remote block and revived the initial oil prospect with another well in March 1994. W the Ivorian government anxious to use the gas by pipeline to fuel an electric power plant, UMC convinced the government that it could deliver gas to the power plant by October 1995, despite the fact that a competing operator had gas in another field to the east. With the obligation to meet the October 1995 gas delivery, an extremely fast-tract scenario was put in place for the total field development, in which a MOPU was to be the Central Production Facility (CPF) receiving well fluids from three caissons. A driving consideration for the overall plan was the lack ofconstruction and oilfield type infrastructure in the area. Figure I shows the general field layout, with Lion 'A' in 235-feet water depth (WD). Lion 'A' and 'B' are predominantly oil, while Panthere is the gas producer.
With a sense of urgency, UMC started design work in May 1994. In the Fall of 1994, UMC anticipated that early production could be achieved via a temporary FPSO tanker arrangement. This was scheduled to start minimal oil production in April 1995. The 58,000-DWT tanker Red Teal was modified as a Floating Storage and Offloading (FSO) unit with some processing capability. A CALM buoy was installed, and the planned oil production from the Lion 'A' was initiated into the Red Teal on schedule during April.
With the design of the MOPS processing equipment proceeding, procurement of long lead production vessels and structure started in August 1994. Initially, the process modules were sized to fit a 250-feet water depth slot-type, mat jack up; however, due to technical and commercial considerations it became apparent in the fall of 1994 that a change to a deepwater independent leg jack up was advantageous, The change of rig design could have had a major impact on the overall schedule since the MOPS was the critical path item.
A Knowledge Based S stem for Economic Analysis and Risk Assessment of Subsea Development z cenarios for Small Oilfields in the North Sea
Authors: Dyer N.J. , Ford J.T. , Tweedie A. 
Published: October 2008

ABSTRACT
The decision to develop a small (C 100 mmbbls) oilfield in the UK sector of the Central/Northern North Sea requires a careful assessment of all aspects of the field development plan:l the reservoir model (reserves and production profile)capital and operating costs, andl the current economic climate (oil price, interest rates, tax regime etc)
This paper describes the development of a knowledge based software package that allows a 'quick look' assessment of the overall economics and risk profile associated with the development of small oilfields in this region. It is a modular system that uses a cost database, cost adjustment algorithms, cash flow analysis engine and simulation procedures to integrate and analyse the impact of reservoir and production characteristics, costs (capex and opex) and economic factors on the decision to develop such a field.
The production system configurations considered by the system are:an unmanned wellhead platform tied back to a third party platform for fluid processing/export,an FPSO with oil export via a shuttle tanker and gas export via a tie-in to the existing North Sea gas pipeline infrastructure, anda straight tie-back from a group of subsea wells to a third party platform for fluid processing/export.

INTRODUCTION
It is generally agreed within the industry that it is extremely difficult to make generalised cost comparisons between alternative field development strategies. This is because the field characteristics vary so widely and have such a large and complex impact on the cost of development, and subsequent financial returns from the project. The software system described in this paper is designed to assist the engineer in this task.
The region selected for analysis was the central and northern sectors of the UK sector of the North Sea. As of March 1995 (ref. I) this region has around 8.3 billion barrels of remainingrecoverable reserves. Of this total, 2.5 billion barrels are associated with fields that are either under development now or probably will be developed in the next 3 to 4 years. Unfortunately the majority of the undeveloped fields are quite small (typically around 30–40 million barrels) and geologically complex.
System Architecture. The overall structure of the package is shown in Figure 1. The core of the system is the cashflow analysis 'engine'. This is a formatted spreadsheet whichallows a cashflow profile, NPV, NPVI and IRR for the project to be computed. This output is generated from the capex (with abandonment costs), opex, field production profile, and the appropriate tax rules and macroeconomic conditions, defined by the user. The spreadsheet is subsequently used to undertake sensitivity analysis, and generate spider diagrams for defined variables, and to allow Monte Carlo simulation for economic risk assessment.
Liuhua 11-1 Development- New Pipeline Technologies for Diverless Connections
Authors: Bludworth Charles K. , Ming Chen , Paull B. Mark , Gates Steve , Manuel William S. , Hervey Donald G. 
Published: October 2008

Abstract
This paper provides an overview of the Liuhua infield production and test pipelines, focuses on new technologies used to tie the pipelines into a subsea manifold, and reviews the basis for selection of flexible pipe in preference to steel pipelines.
The infield pipelines consist of two 13.5 -in.-ID flexible pipes for production and one 6. O-in.-ID flexible pipe for well test. Each pipeline riser is approximately 10,300 ft (3, 130 m) long and runs from the subsea manifold below the FPS, Nanhai Tiao Zhan, to the FPSO tanker, Nanhai Sheng Li.
The technologies used to tie the pipelines into the subsea manifold involved:A transition tie-in base into which the flexible pipe was pulled using ROV-assisted tooling to make up the first end connectorA rigid pipe long jumper from the manifold to the tie-in baseThe survey and measurement tools to set up the jumper welding jigs
Each new pipeline tie-in technology was proven through field tests of actual components before completion of manufacturing and installation.

Flexible vs. Rigid Pipelines
An overview of the manifold-to-pipeline system is provided in Fig. 1. Amoco uses two subsea connection techniques for the Liuhua subsea connection system. To understand how this occurred, a brief history on the Liuhua pipelines is presented. A more detailed discussion of the history and economics of the flexible pipeline selection has been presented previously (Refs. 1 and 2).
During the defining stage, the Liuhua pipeline system consisted of three pipelines - two production and one test. The pipelines were to be of all-steel construction, fabricated either onshore or in shallow water and towed to site prior to the arrival of the vessels. Once the FPS was on site, the pipelines and manifold would be connected via a long jumper that spanned up to 150 ft between the manifold and the lead tow sled.
At Coflexip's (now Coflexip Stena Offshore) request, Amoco agreed to reconsider the use of flexible pipelines. An all-flexible pipeline system was previously rejected due to its perceived higher cost.
Full-cycle economics - including the rental of riser reels, risk of damage to the pipelines and communication cables during tow, and cost of cable crossings, corrosion inhibition chemicals, maintenance, and corrosion monitoring - was performed after receipt of installation bids. The economic result favored two 13.5-in,-ID flexible pipes for production and one 6,0-in, ID-flexible pipe for well testing. In addition, this solution outperformed the rigid pipeline option with respect to risk of damage or failure.
Once awarded the work, Coflexip Stena worked with Amoco to develop an acceptable method to tie the pipelines into the manifold. The designed for steel pipelines, did not permit significant horizontal loads on the manifoldduring a flexible pipe lay away. Pile-founded tie-in bases were selected to resist lay-away loads with rigid-pipe long jumpers connecting them to the manifold.
The limits of reliability theory and the reliability of limit state theory applied to pipelines
Authors: Palmer Andrew 
Published: October 2008

Abstract
Two distinct concepts have been developed in general structural engineering and are now being applied to pipelines. Limit state thinking focuses on conditions that directly threaten the security or operability of a system, and have already been adopted into several codes applicable to offshore pipelines. Reliability theory attempts to quantify the safety of a system by statistical arguments.
The paper examines how far limit state methods can be exploited in marine pipeline engineering without underpinning them by reliability theory. It explores this application of reliability theory, and suggests that in this instance - as in many others - the data needed for confidence are not available (and in many instances can never be available). As in structural failures generally, a majority of pipeline failures are beyond the reach of reliability theory. Paradoxically, this fact may strengthen the case for the adoption of less conservative requirements on limit states, because the real increase in risk is often zero m extremely small.
These arguments are then applied to a discussion of the allowable circumferential stress in pipelines where traditional design factors have often been copied from code to code.

Introduction
This paper explores the application of limit-state and reliability methods, primarily in the pipeline industry. These concepts are widely applied in other areas of civil engineering, notably in steel structure design and in concrete design, and in geotechnics. pipeline engineering has 10 some extent lagged behind in this development, at least in its more explicit forms, though it cart be argued that some of the methods customarily applied to pipelines apply limit state ideas implicitly. Limit state concepts have however influenced the Dutch code NEN3650, the Russian SNiP 2.05.06-85, the Canadian CSA Z662-94, ANSI B31 .8, the British BS 801 O: Part 3 and the 1995 Germanischer Lloyd rules.
The two groups of concepts spoken of as 'limit state' and 'reliability' are separate and distinct. In a historical perspective, the two concepts have only relatively recently become intertwined and .sometimes confused, not always advantageously.

Limit states
Limit-state structural engineering are completely central, and far from new. A structure can become unserviceable in various ways. It can collapse, bits can off, deflections can damage internal finishes or make it impossible 10 operate, oscillations can be so large that the occupants feel uncomfortable, and so on, Each of these conditions defines a limit state in which the structure becomes unfit for purpose. Engineers have thought in these terms from the earliest times. The Roman engineers who designed aqueducts like the Pent du Gard must have asked similar questions how do 1 proportion the arches w that they do not be lapse as soon as the is removed, is there a risk of by crushing, is there a risk of progressive distress because of settlement of foundations, and so on.
Defining Coiled Tubing Limits- A New Approach
Authors: Newman K.R. , Stone L.R. , Wolhart L.C.S. 
Published: October 2008

Abstract
The burst, collapse and axial load operating limits for Coiled Tubing (CT) are currently established using the Von Mises incipient yield criterion. This criterion has historically been used to calculate the limits for oil country tubular goods (OCTG), The limits according to this criterion are based on the point at which the pipe material reaches a load state in which it begins to yield. Because of the bending that occurs when the CT is spooled on and off the reel, and when it is bent over the guide arch, the CT is already far beyond the yield point before it enters a well. Thus, this criterion does not really apply to CT.
This paper describes a research project currently in progress, The purpose of this project is to define a new set of CT limits based on criteria other than 'incipient yield'. This new approach to setting CT operating limits takes into account the internal residual stresses in the CT which are a consequence of repeated bending cycles and the accompanying change in material properties.

Introduction
The use of the Von Mises incipient yield criterion to establish CT limits is discussed in detail in Refs. I through 4. This criterion calculates the tri-axial stresses (axial, tangential and radial) caused by the forces applied on the CT due to the following:axial force (tensile or compressive),internal pressure,external pressure,bending due to helical buckling.
The tri-axial stresses caused by these externally applied forces and pressures are combined using the Von Mises criterion to calculate the Von Mises stress, ?vme. This combined stress, ?vmeis then compared to the yield stress, ?ym CT, P, which is determined from a uni-axial pull test on a sample of the CT. When ?vme reaches ?ym, it is assumed that the CT material will begin to yield. This point of 'incipient yield' is currently used by the CT industry to determine the burst. collapse, tensile and compressive limits that the CT can be subjected to.
However, this method ignores the internal residual stresses in the CT caused by the bending that occurs when the CT is bent on and off the reel and over the guide arch. These esidual stresses cause yielding to begin much earlier than predicted by this method.
The material used to make CT has a well-defined yield point in the axial direction. However, beyond the yield point ?yp, the Bauschinger effect and work softening change ?yp and make it less well defined. Also, in the tangential or hoop direction may not be the same as ?yp in the axial direction.
The Gas Research Institute (GRI) has funded a research project to understand and model the material characteristics and to develop an improved method for setting CT limits.
Coiled Tubing Deployed ESP on the Auk Platform
Authors: Stewart D.W. , Centrilift Paul Watkins , Hottslag R.J. , Hudson A. , Wee P.Y. , McCleery B. 
Published: October 2008

ABSTRACT
In March 1995, what is believed to be the worlds first offshore coiled tubing deployed electrical submersible pump (ESP) was successfully commissioned in well AA-03Sl on Shell U.K. Exploration and Production (Shell Expro) Auk platform in the United Kingdom's Central North Sea. The ESP provides a new and important method of artificial lift for the 21 year old Auk platform, which hitherto had relied upon downhole hydraulic jet pumps to lift approximately half of the platform's oil production. The coiled tubing deploymentproved the viability of performing future work over with or without the assistance or indeed the presence of a drilling package.
The novel completion design successfully catered for the wide variety of customer requirements; Well Engineering for a rigless workover, Petroleum Engineering for reservoir access and Facilities Engineering for a specified flowline height The experience gained during this project will be a valuable input in determining the future artificial lift strategy for this platform and for other prospects in terms of performance, reliability and operating costs.

Introduction
The Auk Alpha platform was brought on stream in 1975, producing from 11 oil wells. The reservoir pressure is supported by a strong aquifer drive and the fields water cut has currently reached 70%, The GORs are low, at approximately 175 sef/bbl with a bubble point of 680 psi. The existing method of artificial lift is by wire line retrievable ?downhole hydraulic jet pump, However, due to the limited capacity of the permanent artificial lift (PAL) system, no more than three wells could be lifted simultaneously. It was against this background that the decision was taken to proceed with a trial ESP installation as a complementary method of artificial lift. After deciding to use an ESP pump on the Auk (the first within Shell Expro) the method of deployment had to be considered, conventional deployment versus cable or coiled tubing deployment
The preliminary work showed that using either cable or coiled tubing as the means of deployment for the ESP could give rise to significant savings. Opex reduction of 20% on future workoversInstallation times reduced by 50%. Bedding reduction of circa 100 mandays per workover
The use of cable or coiled tubing deployment was also an opportunity to utilize new technology whilst being aware of the risks involved capitalizing on the work already done with large bore coiled tubing by Shell Expro in the Southern North sea.
An invitation to tender was prepared which invited companies to tender for the supply and installation of all components for the completion excluding the tubing hanger and wellhead. They were also required to supply a Project Engineer to work with the Shell Exploration project team to bring the proposal to fruition. After evaluation of tie submitted tenders a pump manufacturer was selected.
Partnering in Practice: Deepwater Pipelay Gulf of Mexico
Authors: Williams Mandy S. , Eckert Michael Don 
Published: October 2008

Abstract
The Mustique flowlines are dual 3-inch diameter pipelines located in 832 feet of water in Garden Banks 236. The Shasta flowlines are dual 4-inch diameter pipelines and are located in 1,040 feet of water in Green Canyon 6. A total of four pipeline end termination skids and 50 miles of pipelines were installed under a partnering agreement between the Lease Operator ('Operator') and its pipeline installation contractor ('Contractor'). The Operator (Hardy Oil & Gas USA, Inc.) represented itself as well as one other working interest owner (Samedan Oil Corp.) in the Mustique project, and the Shasta project included a third working interest owner (Texaco Exploration & Production Inc.)
The most technical challenges of the project were the laying of dual flowlines from the Contractor's reel barge, attd the installation of the flow lines past an intermediate wellhead, as was the case in the Shasta project. The installation of dual termination skids at the intermediate wellhead also required a considerable amount of technical expertise.
The Operator's objective was to achieve specific contracting goals that resulted in cost-effective work that met or exceeded the accepted quality standards of the offshore construction industry, and also to provide a means to maximize the value of each participant's resources and expertise. Partnering, a non-bidding contracting approach, on the Shasta and Mustique projects enabled both the Operator and the Contractor to work together to share the risks involved in the installation of offshore pipelines, as well as share the savings that were realized as a function of working together.

Introduction
'Partnering' has become one of the more popular industry buzz words, not just in the energy sector but throughout the business world. The term 'partnering:' which is often usedinterchangeably with 'alliance' and 'teaming,' is a term the attorneys would prefer we not use as it can be confused with a legal partnership. The partnering arrangement that was used for the Shasta and Mustique projects was not a legal partnership, but rather a carefully developed Project Management Team ('Team') consisting of representatives from the working interest owners in Green Canyon 6 and Garden Banks 236 and the suppliers of equipment and services as they were selected. (Fig. 1) This approach is a way of getting back to a simpler, old-fashioned way of doing business on a handshake; a means of taking responsibility for what you do and not allowing the 'letter of the law' to destroy a successful relationship.

Management Buy-in
Partnering cuts across traditional role perceptions, and attempts to replace adversarial positions with an entirely different mindset that in essence requires major cultural change. Operators that feel rewarded for being good watchdogs over equipment and services supplier's activities, and suppliers who prefer to hide behind the safety of externally developed precise bid specifications, have to develop a different paradigm