bluuebunny/crossref_metadata_2025 huggingface dataset:
Dynamic Characteristics Of A Pipeline Dewatering Train
Authors: Hamid Syed , Falck Christian , Wissing Marcel , Grotberg Ingvar
Published: October 2008

Gas- or liquid-driven pig trains are sometimes used during pipeline dewatering before the line is commissioned for gas transport. Pig trains consist of compartments of drying liquid separated by sealed mechanical pigs. Gels may be used in the front and the rear of the train for various purposes, such as minimizing gas bypass, providing seal lubrication, etc.

Train operation is controlled by modulating the supply gas pressure and controlling the water discharge with a valve opening at the downstream end of the line, The valve opening schedule determines the pig train's rate of acceleration. A very fast opening schedule results in high hydraulic transient pressures that may cause rapid velocity changes. An opening schedule that is too slow would cause "start-stop" or "jerky" pig movement, which could result in forward gas bypass. Both of these effects tend to degrade train performance.

To help estimate the characteristics of a pig train for a given operating schedule, a numerical simulator has been developed. This simulator incorporates mathematical models of the pigs, the fluid compartments, the pipeline geometry, and the downstream control valve. The fluid compartments and the liquid portion of the pipeline are modeled with the method of characteristics while taking into account the non-Newtonian character of the gel rheology. Coulomb friction along with stiction is used to model the pigs.

The simulator has been used to design dewatering train startup and shutdown schedules for two methanol swabbing operations involving two subsea Zeepipe pipeline systems: one 814 km (505 mi.) long and the other 250 km (155 mi.) long. These trains have consisted of several pigs with methanol and gel compartments. Unscheduled abrupt shutdowns have also been simulated. The methods developed can be applied to the general case in which pigs are used for fluid separation.

The performance of the two actual pipelines illustrates the significance of the new approach relative to the startup and shutdown of pig trains in general.

This paper describes the dynamic mechanisms involved in pig trains and abolishes certain intuitively developed paradigms, such as starting a train "very slowly" to minimize the hydraulic transients.

Introduction

Pipelines are normally hydrotested for mechanical integrity either after a repair job or after the initial installation. After hydrotest have been performed, a line is dewatered and dried before it can be commissioned for gas transport.1,2

A dewatering system involves a displacement fluid supply, a dewatering train, and a valve for water flow rate control (Fig. 1). The dewatering train takes up different configurations depending upon the size of the pipeline. In pipelines shorter than 50 km (30 mi.), a small number of mechanical (foam or wiper seal) pigs can be driven with nitrogen or air, Sometimes produced gas is used to displace the train.
The Albacora Field Subsea Development: A Case History
Authors: Bastes B.L.
Published: October 2008

Subsea technology has proved itself as an alternative for marginal or deep water field developments. This paper will describe six years of operational experience on the Albacora field, an important subsea development project being carried out offshore Brazil. Main results and major difficulties encountered during this period will be discussed in the text.

INTRODUCTION

Albacora is one of the last decade discovered deep water giant fields, located at Campos Basin, offshore Brazil. Being explorated since 1968, Campos Basin became the main petroleum province in Brazil. Ranging from shore to 3,400 m WD, with a total area of 110,000 Km2 its total proved reserves, in WD u; to 1,000 m, reaches 2.78 X 109 barrels of oil and 58.2 × 109 std m3 of gas, 16 % of this being located in the Albacora field (Fig. 1).

In 1984, with the wiIdcat well 1RJS297, drilled at 293 m WD, the Albacora field was discovered. Further efforts led to the knowledge of the field's full extension, which is presently accepted as covering an area of nearly 235 Km2. Since this first discovery and the following successes in Marlin field, the basin development strategies had been reviewed to attain those new chal Ienges in deep waters.

GEOLOGY OF THE ALBACORA FIELD

The Albacora field is located nearly 110 Km from the coast, in water depths varying from 230 to 1600 m. Its main oil occurrences are found in the Tertiary / oligocene, Eocene and Miocene sandstones (Campos/Carapebus) and in the Cretaceous/Albian sandstones (Macae/Namorado), all of turbiditic origin (Fig.2). A total of eight different oil reservoirs ranges from 2350 to 3260 m TVD, with a significant variation in porosity, water saturation, oil gravity, etc2. Its proved reserves are of 0.455 × 109 barrels of 26/29 °API oil and 8.48 × 109 std m3 of gas.

FIELD DEVELOPMENT MILESTONES

To cope with geological and reservoir uncertainties, as well as technological limitations and budget requirements related to the deep water / giant field combination, it has been planned to develop the Albacora field by stages. Each stage provides reservoir data, technology field testing and early cash flow to support the following stages3,4,5. The project's milestones are listed bellow:1984 - Drilling of the well 1RJS297, discoverer of the field;1987 - Drilling and successful testing of the well 1RJS367 at 1565 m WD, a world record;1987 - Phase 1 (Pilot System) start-up: The Pilot System comprised 6 wells connected to a diver assisted subsea manifold, producing to a FPSO consisted of a tanker (P.P. Moraes) and a monobuoy in SBS configuration, at 230 m WD. This conception combines a CALM type monobuoy rigidly connected through a yoke to the tanker. OiI sales were conducted through the SBS monobuoy to a shuttle tanker tied to a second monobuoy.
Deepwater Production: 1950-2000
Authors: Dunn F.P.
Published: October 2008

INTRODUCTION

A tension leg platform was just recently installed in the Gulf of Mexico in almost 3000 feet of water. How did the industry get there? Possibly more significantly, how much deeper can we go, and when? I will try to answer the first question by reviewing the history of offshore operations, and I'll then make a stab at answering the other two questions.

In addressing the first question, I will focus primarily on technical developments over the past 40+ years in several areas: knowledge of the environment, e.g., oceanography, hydrodynamics, meteorology, and to a less extent, seismicity; analysis; design; soil mechanics/ geotechnology; materials; construction; and instrumentation, testing and calibration. Of course, overshadowing all of these subjects is economics-the bottom line-but my emphasis will be on the technical areas.

I will concentrate on steel drilling/production structures in the Gulf of Mexico and Offshore California, fully realizing that concrete structures have played and will play a significant role in deep water, certainly in the North Sea, and quite possibly in the Gulf of Mexico in the future.

I have divided the fifty-year period somewhat notionally into five segments: The Beginnings; The Learning Curve; Maturity; Alternatives; The Future.

THE BEGINNINGS

One of the first offshore drilling operations took place in 1938 in 18 feet of water, about 1-1/2 miles offshore Texas, from a wooden deck platform supported by 100 timber piles, each 65 feet long. A long trestle to shore, supporting railroad tracks, supplied the platform.

The first "permanent" steel platform (the timber platform noted above was severely damaged by a 1938 hurricane) was installed in 1947 offshore Louisiana in 20 feet of water. The platform employed six templates and was supported by 267 piles made of 8-inch and 10-inch pipe.

The design and construction of such steel platforms were dictated by available sizes of structural members and by existing construction equipment (70-ton crane). Design wave height in 1947 was 32 feet, upped to 40 feet in 1949 when a hurricane hit the Texas Coast. Design wind velocity in 1949 was 125 miles/hour. Wave forces were calculated based upon a chart using solitary wave theory. The forces were less than 1/3 of those which would be used today. Foundation design was based upon a series of seven core tests, some taken to 400 feet, along the eastern Louisiana coast. Pile driveability tests were also conducted to 165 feet of penetration.

By 1953, seventy steel platforms had been installed, the deepest in 70 feet of water. In 1955, a platform was installed in 100 feet of water, followed in 1959 by the installation of a 4-pile "minimum" platform in 204 feet of water.

Major advances during this period were in the area of installation equipment. A 150-ton derrick barge specifically built for offshore use was available in 1950. By 1953, another barge of 250-ton capacity was in service. Platforms were lifted into place by the crane, not launched. If the platform weighed too much for one crane, two were used.
Welding And Ndt Development In Support Of Oman - India Gas Pipeline
Authors: Even Thomas M. , Laingv Brian , Hirsch Dan
Published: October 2008

The Oman to India gas pipeline is designed for a maximum water depth of 3500 m. For such a pipeline, resistance to hydrostatic collapse is a critical factor and dictates that ery heavy wall pipe be used, preliminarily 24 "ID × 1.625" wall. Because of the water depth, much of the installation will be by J-Lay which requires that the Joint be welded and inspected in a single station. This paper describes the results of welding and ND T test programs conducted to determine the minimum time to perform these operations inheavy wall pipe .

INTRODUCTION

The Oman Oil Company is implementing the Oman to India gas pipeline project. The offshore section of this pipeline is 1139 Km long, between Ra's al Jifan in Oman and Rapar Gadhwali in India, in water depths up to 3500 Meters, Approximately 80?40 of the pipeline route will be in waterdepths where heavy wall pipe is needed to resist hydrostatic collapse, and the J-Lay technique will most likely be used for installation, Using the J-Lay technique equires that joint alignment, welding, inspection and coating all be performed in a single station. Minimizing the time required to perform these operations will have a significant impact on overall construction costs and schedule.

An Industry Review was conducted to identify methodsthat would satisfy the initially projected requirement of 45 min. to complete both welding and NDT. Two welding methods were selected from the review groups to perform the welding test program and four non-destructive methods were selected for the NDT test program.

This paper reports the results of these test programs and indicates areas within each operation where further work is desirable.

Two companies, one using a modified form of GMAW and the other using automatic GTAW with a hot wire feed, were contracted to perform the welding tests listed below,Develop a welding procedure for the 2-G position on26"OD × 41.3mm wall pipe.Demonstrate the procedure on a single weld.Make a series of three consecutive welds, each weld in under 38 minutes.

Both welding systems used a narrow gap technique that, when employed by three units equally spaced around the pipe and welding in unison, was able to complete the weld in under the goal of 38 minutes. The narrow groove minimized the amount of filler metal required, so that welding parameters approaching the maximum deposition rate could be developed.

This report provides details of each welding procedure including filler wire, shielding gas, travel speed, arc parameters, and joint design.

Four companies were selected to perform the NDT portion of the program as follows:Develop a NDT procedure for inspection of 26" OD × 41 .3mm wall API X60 pipe weld in the 2G position.Demonstrate the procedure cycle time,

The processes used for this work are; Film radiography, Real Time Radiography, Mechanized ultrasonic testing(Pipeline system), and Mechanized ultrasonic testing (Pressure vessel system).
The Suction Mooring, A New Type of Offshore Single Point Mooring
Authors: Korsgaard Jens , Hutter Louk
Published: October 2008

Existing systems for mooring offshore oil production vessels of the ship type only permit the mooring or tying up of the vessel in quite lowwave conditions. Virtually all existing systems do not permit the vessel to moor in wave conditions exceeding H. = 4.5 m. Most systems require wave heights smaller yet to moor. This is a problem in cases where frequent mooring operations are required such as for shuttle tankers and for disconnectable oil production or storage vessels moored in areas with a high incidence of tropical storms. The wait for the waves to subside following the storm causes additional production losses due to the oil field being shut in.

A newly developed mooring system, the suction mooring, promises to overcome this problem by permitting the mooring of the vessels in wave heights to at least H= = 8 m. The principle of the mooring consists of using the hydrostatic pressure available at the keel of the vessel to press a mooring buoy onto the bottom and holding the vessel by the resulting friction. The action of the mooring buoy is similar to that of a suction cup.

The pressure above the buoy is lowered and maintained low by means of pumps aboard the vessel.

This paper reports on model tests carried out to prove the feasibility of conducting the mooring operations in high waves. Three different configurations of the mooring buoy were tested. For two of the configurations it was found that the mooring process could be carried out safely in all wave heights tested i.e. up to H. = 7.7 m.

The impact upon offshore operations of this capability was investigated by performing Monte Carlo simulations on a hypothetical oil field in the center North Sea and in the northern North Sea. An actual center North Sea wave record was used in the simulations.

The suction mooring system was compared to two other high performance mooring systems. The results show that weather related oil field shut-ins re reduced an order of magnitude by application of the suction mooring compared to the other systems simulated.

MOORING PRINCIPLE

The suction mooring principle involves mooring a submersible buoy to the bottom of a vessel utilizing differential hydrostatic pressure, in a manner similar to a suction cup.

A mooring buoy is brought into contact with the flat portion of the bottom of the ship either by means of a retrieval line such as commonly usedfor the Buoyant Turret Mooring (BTM) and Submerged Turret Loading (STL) type mooring or by means of reduced buoyancy utilizing a system aboard the buoy to control the buoyancy.

The reduction in hydrostatic pressure above the buoy is provided by pumps aboard the ship. A bow thruster pump of the Omni-thruster or the Elliott Turbo Machinery type having its intake at the keel in the mooring area is used to achieve the initial pressure reductions. This type of pump has a capacity from 4 to 11 m 3 /sec.
Advanced Mooring Method for Installation of Enserch Mooring Legs Garden Banks 388 FPF
Authors: Honig H.J. , Koolwijk W.
Published: October 2008

In the fall of 1994 HeereMac v.o.C installed the 12 mooring legs for Enserch Exploration's Floating Production Facility in Garden Banks Block 388 in the Gulf of Mexico with the SSCV Balder. The installation of the catenary mooring system, each leg comprising several raying sections of spiral strand wire and chain, required sufficient handling and manocuvrarability power of the vessel, while enough holding capacity and stiffness of the system had to be provided.

The most important aspects of the actual installation of the mooring legs are explained, for example, the w of a purpose built tipping winch.

The method selected by HeereMac for station-keeping the Balder was to use a minimum number of anchor lines in combination with a tug, in order to maintain position and at the same time have an easy and controlled method of manoeuvring to a new position. Themethod of station-keeping the SSCV in this way is part of a development towards full position control with a spread of tugs. In this paper the station-keeping system is described and the offshore experiences with the system are discussed. Some future developments with respect to tug-assisted station-keeping systems are highlighted.

INTRODUCTION

In November 1994 HeereMac v.o.f installed the mooring system for the Ensach Garden Banks Floating Production Facility (FPF). The installation took place in Garden Banks Block 388 in the Gulf of Mexico and was performed by the Semi-Submersible Crane Vessel (SSCV) Balder. The water depth at the installation site varied from 2100 ft. to 2550 tl.. The FPF mooring system consisted of 12 mooring lines in a regular pattern (at intervals of 30 degrees) with leg lengths varying between 7650 ft. and 9000 ft. (see Figure 1). Allmooring leg components were delivered by Enserch to the HeereMac base port in Fonrchon (Louisiana), where all components werechecked and marked, and trial tit-ups were performed. The mooring leg components were transported from the base pat to the installation site on three barges, a 250 tl. × 72 tl. barge for the transport of the chains of the fust six mooring lines, a 260 ft. × 72 tt. barge for the chains of the remaining six mooring lines, and the MWW03, a 400 tl. × 105 ft. barge, for the transport of all the othermooring leg components.

Only twice was it necessary to transfer a full batch of all components of six mooring legs from the cargo barge to the &ck of the SSCV (see SSCV deck lay-out, Figure 2). Before the job started all systems had been extensively tested in order to avoid surprises during the installation. Each anchor had to be set within an envelope measuring 100 ft.perpendicular to the leg and 50 ft. along the leg direction around the anchor setting co-ordinates.. The anchor lines had to be installed within a corridor of 50 R. on either side of the target-setting line. This paper gives a description of the project and the installation aspects. Special attention is paid to the station-keeping of the SSCV.
Dynamics of a Near- Surface Pipeline Tow
Authors: Binns Jonathan  R. , Marcollo Hayden , Hinwood Jon , Doctors Lawrence  J.
Published: October 2008

1. Introduction

This project arose from a series of experiments carried out by the Melbourne node of the Australian Maritime Engineering Cooperative Research Centre (AMECRC) at Monash University in 1993 for the Australian Marine and Offshore Group Pty Ltd. During these experiments, a model pipeline string simulating a 400 m long full-scrde pipe was tested for a 15 km near-surface tow to deep water. The pipe was made approximately neutrally buoyant by the use of buoyancy cans and chains. It then acted as a beam excited by the waves.

The main concerns for this operation were that, under all expected wave conditions, the pipe stresses should not be excessive, and an estimate for the power required to tow the pipe should be determined for a range of waves and towing speeds. It was considered that an experimental study was necessruy because of uncertainties and the non-linear nature of the processes.

This paper reports on an experimental and computational sequel to the original testing project, aimed at developing and veri&ing a numerical model of the pipeline response to wave action. The overall aims of the research conducted were to uncover the relationships controlling the transverse vibration of a smooth pipeline at near-surface depths in waves by including towing speed and back tension. In the following sections, the problem is specified, the numerical method developed and sample output fi-om the numerical method presented. Sections 5 and 6 describe the experimental procedure and results. Sections 7 and 8 compare the numerical results, draw conclusions and suggest some applications of the results.

2 Predictions of Pipe Motions

2.1 Problem Formulation

The first task in predicting the pipe motions was to derive the differential equation governing the motion of the pipe. This was done by balancing the forces on a small element of pipe. The element of pipe considered is shown in Figure 1. This is the standard element used in vibrational analysis of a beam with the inclusion of the hydrodynamic forces. In the figure, V is the internal shear force due to the adjacent pipe elements, M is the internal bending moment and T is the tension force supplied by the adjacent pipe elements. The pipe is considered to be neutrally buoyant. Hence, its weight has not been included. The virtual mass in the equation consists of the actual mass of the pipe element plus the added mass. The hydrodynamic loading for a slender cylinder is assumed to be described by the Morison equation with drag and inertia coefficients taken from Sarpkaya and de St.Q. Isaacson (1981).

2.2 Equations of Motion

The final differential equation is

(Available In Full Paper)

where p is the water density, d is the pipe diameter and Cd and Cm are the Morison drag and inertia coefficients. Also in Equation (l), EI is the bending stiffness of the pipe, T is the tension in the pipe, A is the cross-sectional area of the pipe and & is the velocity of the water due to wave action.
High Integrity Pressure Protection Systems for Production Applications
Authors: Langvik S. , Aarebrot E.
Published: October 2008

Through the use of a High Integrity Pressure Protection System (HIPP$) the flare capacity of a well head platform can be reduced to the flowrate required for depressurisation. The HIPPS may also be used to reduce the are capacity of a process plant. By the use of HIPPS, the discharge of hydrocarbons or carbon dioxide due to venting/flaring is reduced.

This paper describes the development of HIPPS for the Sleipner B-platform offshore Norway. A 20" multiphase pipeline is protected against overpressure by two 20" quick acting shut down valves (QW installed in series, instead ofpressure safety valves. The valves have been qualified for operation in well stream at a shut-in pressure of 336 bar, and have a closing time of 2 seconds. Each of the QSKS has independent, fail safe instrumentation circuits. A parallel rain of QSV.s has been installed due to the testing requirements. The estimated saving using HIPPS on SLB was $25 mill.

The paper also discuss existing and new applications of the HIPPS.

INTRODUCTION

The Sleirmer Vest is a gas field, containing 33 billion Sm 3 of sales gas 29 million of code oil and; mill. tons of NGL. The development consists of two platforms, a wellhead platform (SLB), and a gas treatment platform (SLT). Platform production is 20.5 mill Sm3/Dof sales gas and 450 Sm3/hrof condensate(including NGL). Sleipner Vest will come on stream in 1996.

The well head platform is connected to the treatment platform via a 20" multiphase pipeline. The Sleipner Vest interfiled pipeline has a design pressure of 160 barg, while the wellhead shut-in pressure on Sleipner B is 336 barg. It is therefore necessary to protect the pipeline against the wellhead pressure. The flowrate in the pipeline is 250 kg/s. The main scenarios for over pressure in the pipeline was considered to be hydrate formation, pigging and closing of the inlet valve on Sleipner T.

A flare system designed for blocked outlet, i.e. fill flow, is Expensive at the high flow rate required (250 kg). It was therefore decided to use a HIPPS. The HIPPS on Sleipner B is shown in figure 1.

PROBLEM DESCRIPTION

For this paper HIPPS is defined to be a system for Over pressure protection of process equipment by utilizing dedicated shutdown valves. The HIPPS system protects the equipment against over pressure by closing down the source of the over pressure.

HIPPS has been used offshore in production systems for several applications, mostly for tie-ins of new fields to existing platforms, or as a modification to platforms where the flare capacity is limiting for the oil production. A number of different valve types, instrumentation concepts, valve configuration etc. has been used. In terms of equipment, valve configuration etc.

API RF'14C, ref. /1/, has traditionally been used for design of process safety systems offshore, but does not describe the application of HIPPS. Overpressure protection by the use of double shut down valves is permitted for wells, but the use of additional PSVS are still recommended by API.
Analysis of Jack-Up Units During Transit With Legs Lowered
Authors: Chakrabarti Partha , Halbleib Byron , Laird John
Published: October 2008

Conventionally jack-up units are transported from one location to another with the majority of their legs extended above the hull. On certain occasions, due to possible storm conditions, they must lower their legs below the hull significantly to maintain expected vessel motions within an acceptable level. During a storm, the unit will respond with six degrees of motion while afloat. The extended portion of the legs below the hull will be subjected to drag loads. Unlike the condition with legs extended in air, analysis of a jack-up with its legs lowered below the hull has not been widely reported in published literature. The present paper reports the motion analysis of a jack-up for different leg drafts and indicates the safe limits up to which the leg can be extended below the hull without overstressing it.

INTRODUCTION

When a jack-up unit is in a transit condition either during a field move or during ocean tow, there is always a probability that it cou [d be subjected to a storm. For afloat operations, the rig must meet the stability and structural criteria prescribed by the classification societies, such as ABS1. For rigs in severe storm transit condition, ABS requirement states:

Legs are to withstand acceleration and gravity bending moments resulting from the motions in the most severe anticipated environmental transit conditions, together with wind moments correspond ng to a velocity of not less than 51.5 m/s (100 kn). ... Alternately, legs are to withstand a bending moment caused by minimum criteria of a 15 degree single amplitude roll or pitch at a 10 second period, plus 120% of the gravity moment caused by the angle of inclination of the legs. ... Intact stability of the unit is to be investigated ... for a wind velocity of not less than 51.5 M (100 knots).

On many occasions, especially for rigs having relatively long legs, in order to satisfy these criteria, the legs have to be lowered considerably. For example, some Global Marine Jack-up units of Marathon LeTourneau 116-C design with 477 ft of leg, which this paper addresses, require a leg draft of 184 ft to satisfy these criteria.

It is obvious that rig motions are influenced by the draft of its legs. During a storm, the portion of the leg below the hull is subjected to a combination of wave forces, motioninduced drag loads, as well as inertia loads. It is not obvious, though, whether there is a limit for increasing the leg draft in order to meet the ABS criteria without causing structural problems to the portion of the leg extended below the hull. This paper investigates the motion characteristicsof a typical Marathon LeTourneau 116-C jack-up with 477 ft leg length with various leg drafts using 3-dimensional radiation-diffraction theory, and attempts to estimate thesafe limit of the leg draft for the roll/pitch criteria specified by ABS.

MOTION RESPONSE

The hull of the rig has been modelled by using 680 panels as shown in Fig. 1.
Application Of Low Density Foam Pigs Offshore Brazil
Authors: Lima P.C.R. , Alves S.J.
Published: October 2008

In complex offshore installations, such as in the Campos Basin, it is relatively common to encounter pipeline systems where conventional pigs can not be run due to several factors. Changing pipe diameters, and presence of wet Xmas trees and manifolds are the most troublesome ones. In this work a new successful concept of using low cost and low density foam pigs for both liquid removal in wet-gas pipelines, and parafin removal in oil and multiphase flow pipelines, is presented. Experimental work conducted in a 4 in laboratory facility, including a small scale glass manifolds and a 6 in steel manifold proved these pigs to be very effective. The performance of almost all kind of flexible polyurethane foams manufactured in Brazil is evaluated.

Three field tests are also reported. The first low density foam pig operation was performed on a 127 mile long, 16 in diameter wet-gas offshore pipeline where the foam pig showed even higher liquid removal efficiency than the conventional inflatable spheres. The second operation was performed on a 6 mile long, 12 in diameter multiphase production offshore pipeline, which has never been pigged during its 9 year operation, and resulted in the removal of approximately 200 tons of paraffin. Finally, the third successful case is the cleaning of a 2 mile long flexible flow line of a subsea completed satellite well, in which the foam pigs were sent through a 2.5 in gas Lift line, through a wet x-mas tree, not designed to be pigged and then back through the 4 in production flow line.

In spite of the fact that this paper is focusing on condensate and paraffin removal in pipeline, the basic principles can be applied to several kind of operations: general pipeline cleaning; product separation in pipeline; corrosion evaluation; chemical product application.

LOW DENSITY FLEXIBLE FOAM

The developed pigs are manufactured from polyurethane foam block, mainly supplied by flexible foam Brazilian industries. There are two basic polyurethane materials: polyeter and polyester. They present significant differences in chemical and mechanical properties. The foam density range varies from 1.1 to 2.4 lbm/ft3. The pigs are shaped using a special device designed and constructed by PETROBRAS.

The physical properties considered for foam selection were:density;tensile strength;wear resistance;tearing resistance;resilience;elasticity modules;type (closed or open) and size of foam cells.

LABORATORY TESTS

Fig. 1 shows a schematic drawing of the field scale test loop, especially constructed to evaluate the performance of foam pigs. The 157 ft long test loop was composed of a 4 in, such 80 steel pipe, equipped with a 6 in pig launcher, a variable diameter spool piece, a transparent section and a tank to receive the liquid displaced by the pig. The liquid phase was either water or light refined oil. The air was supplied by a 49500 scfld and a 200 psi maximum discharge pressure compressor.

The following laboratory tests were performed:

(Available In Full Paper)
Project Development in a New Era
Authors: Vold Johan Nic
Published: October 2008

1. Introduction

I too will like to thank the organisers for standing so firmly behind this Norwegian day at OTC ?95. I certainly hope that you will benefit from our North Sea experience. We are reasonably proud of what the Norwegian oil industry can offer. I will however at the outset underline that we are fully aware that our recent history is only one of many examples of the dynamic nature of our industry.. ... And although the many short sessions that follow may not allow time for repeating more general points, we are all filly aware that our achievements havenot come about in isolation. Co-operation and competition on a global basis has been a vital ingredient to our current strength.

Our business environment is undergoing rapid and iimdarnental changes, The dramatic downward adjustment in the outlook for oil prices is only one of many challenges facing our industry. Competition for the most attractive assets is intense. A new era has started. Financial strength, technical excellence and world class reputation is required to succeed. But this alone will not be sufficient. The most success lid companies will be the ones with an innovative and focused - but still flexible - organisation. Working more closely together with our suppliers and other oil and energycompanies will also be a prerequisite.

In this new era we have to rethink our project development processes, how to identify new projects and business opportunities. Indeed, creating a shift in our project development capabilities is vital if we are to achieve the required improvement in our profitability.

2 A new era

2.1 Markets

Before I proceed with the topic of project development, let me first briefly touch on someof the issues that are likely to characterise the new era.

Today, our outlook on oil markets is radically different from when most of us were shaping our perceptions about best practice - be it in terms of work processes, technology, control systems, supplier relationships and regulatory framework, For example, the second phase of the 1.7 billion barrel Gullfaks field was approved for development in 1985. That year the oil price expectations were close to 40 94-USD/barrel.

Today new developments have to reach at least 10% real rate of return at 16 USD to be considered. And we are no longer looking towards the oil market to pull us out of our difficulties, In my view, there are limited prospects for sustainable oil price increase. Oil markets will probably be even more volatile and we are preparing for lower growth in Statoil?s main markets.

The gas industry seems however to have a more positive outlook. In Europe, I believe we will see a growth in demand, triggered by economic growth and the increasing efficiency of gas based power generation. Environmental awareness and subsequent legislation are also important factors driving the demand for natural gas. Even gas is suffering from the dramatic increases in consumer government taxes - seemingly approved in support of a better environment.
New Elements in Production Technology and Operations
Authors: Melberg Ole
Published: October 2008

The title of this presentation embraces quite a wide scope, however, focus will be on Mobile Production Systems (MPSS) and in particular on Floating Production, Storage and Offloading Units (FPSOS), for which we are presently witnessing a remarkable boost in interest particularly in the North Sea area.

Over the last 20 years, pioneered by the Argyll TW 58 in 1975, 11 mobile systems have been/ are active in the North Sea, i.e. a growth of one for each second year. In 1994 alone a number of eight mobile production systems were contracted of which seven were FPSOS, This boost is following nine years of successful operation of the Petrojarl I and is also clearly linked to the success of the Kerr-McGee?s Gryphon A project.

The title of this presentation reflects new elements in this business; the upturn in interest for FPSOS introduces new ways of thinking and acting. In this paper, the new elements are divided into the general trends; new commercial elements and new technological elements.

GENERAL TRENDS

Over the last 20 years the industry has seen around 70 applications of MPSS in terms of monohulls, semisubmersibles or jack-up solutions. Out of these a number of 11 are related to the North Sea.

Only 10% of the applications are dedicated New buildings. Monohull solutions, which are normally converted tankers, account for less than 40%. of the cases on a worldwide basis.

This presentation will deal with the business of mobile production systems in general, but the discussions of "new elements" are mainly related to the trends in the North Sea, UK and Norwegian sectors.

The Gryphon A project, see Figure 1, that saw first oil in October of 1993 seems to represent a break-through for the dedicated monohull field development. The positive experiences from 1.5 year of operation on Gryphon has certainly had a positive effect on the dedicated monohull newbuildings seen in 1994.

The MPS applications in the North Sea up to 1994 are shown in Figure 2. There are seven semis of which six are conversions. Three ships, all dedicated newbuilds for production, The West Omikron is a converted jack-up for water injection in the Ekofisk field.

The two main parameters when selecting the concept is the water depth and the presence or not of infrastructure, see Figure 3. The major difference between the semi andthe FPSO is the storage capability and thereby the FPSO?s merit as a stand-alone solution.

The main difference between the floating semi or FPSO and the seabed based jack-up is the water depth.

If pipeline offtake is available the semi or jack-up solutions are attractive, When storage is needed the FPSO is the superior solution.

When designing a system for a number of future fields for which the input parameters are not known, the FPSO solution is the most versatile offering all functions from one vessel only, This is certainly influencing the trend towards monohull solutions when contract duration field lifetime is less than say 10 years.
The Statfjord Satellites - Challenges and Experiences during Development and Production Start Up
Authors: Malmin Per Chr.
Published: October 2008

Production from the Statfjord Ø st field has been started up as planned, and the project completed within the overall budget, This paper reviews the handling of the more significant problems that have been encountered during the development phase, and give as a summary of the initial experiences alter production start-up.

After a description of the Statfjord satellite fields, the paper gives a resume of the major tasks encountered during the development of these fields. Tha extensive modifications to the Statfjord platform required by this project, were performed while the platform was producing at its maximum capacity. Manning level and control of hot-work were two major issues in this context. In addition, the project team was able to add the necessary subsea equipment to ensure timely start-up of gas production at Sleipner to the scope of the project. Two areas of environmental concern are described, the reduction of flaring during well testing, and the containment of C02emissions as power consumption on the platform was increased.

Production Porn the two fields started in September 1994 and January 1995, respectively. Alter an initial running-in phase of a few weeks, production has been very stable. The i7nal challenge to be overcome to star production, was the need to get an agreement to reduce the continuous high production at Statfjord C, in order toprovide processing capacity for the v Satellites.

THE STATFJORD SATELLITE FIELDS

The Statfjord satellite fields are two oil fields located in the vicinity of the Statfjord field in the Norwegian Sector of the North Sea as shown in Fig. 1, at water depths of 150 to 290 m. The two fields have different owner groups. Statfjord Nerd, 17 km north of Statfjord C, is located in Block 33/9 and is owned by the NorwegianProduction License 037 (the PL037 group), which also has a majority ownership in the main Statfjord Field. Statfjord Ø st, 7 km east of Statfjord 'C, is located in Blocks 33/9 and 3417 and is owned 50% by the PL037 group and 50"A by the PL089 group. The fields were discovered in 1977 and 1976, respectively.

The reservoirs in both fields are Brent sands of mid-Jurassic age. At Statfjord Nerd, there is also a reservoir of Volgian sand of upper-Jurassic age. Both fields contain oil with associated gas and have good reservoir properties. The original estimates of recoverable reserves in Statfjord Ø st are 19 mill Sm3, and in Statfjord Nerd 27 mill Sm3. Each field will be produced through six or seven walls. In addition, four wells at each field will provide water injection for ressure support.

High intervention cost is a typical property of subsea completions. Therefore a minimum of data acquisition operations are planned. To a certain extent this has been compensated by installation of permanent downhole pressure gauges in the majority of the wells. Further, the wells and the completions have been designed to enable future wireline interventions from avessel. Due to low sand strength in the Statfjord Ø st reservoir, extensive coring.
The Growing Importance of 3-D Seismic Technology
Authors: Schoenberger M.
Published: October 2008

Introduction

3-D seismic technology is arguably the most important E&P technology to have developed during the past few decades. The significance of this technology is illustrated by the exponential growth in its application. Figure 1 illustrated the growth in Exxon's use of this technology-as measured both by the area coved and by money spent on it. What has accounted for this tremendous growth? Will it continue?

This artielc is arranged logically to illustrated how 3-D seismic technology has develop its current status and how it needs to change in order to he even more valuable in the future than it is today.

The Early Days

Note in Figure 1 that 3-D seismic exploration began in the middle 1970s. However, the Wzhnologyused in those early surveys had been developed during the previous duple. 3) Hktundly, Fitly groups contributed to the success of 3-D Seismic exploration. However, in my view, three seminal activities Most of the Credit.

1) During the 1960s Exxon developed the expanding wave front 3-D seismic impark tecludque. In its most common implementation, a lid of geophones was placed orthogonal to a line of shot holes. Each shot detected by the geophones illuminated a line in the subsurface when all shots had been recorded a rectangular subsurface region had been illuminated.

The shot record were placed on movie, film Exxon-developed fiber-optic viewer extracted and displayed all of the data recoded at a give arrived time; i.e., its output was a succession of rime slices through the seismic wave field. Figure 2 shows a succession of wave fronts reflected from a horizontal layer. At 1680ms the dot in the center is the reflection arriving at the nearest offsets. At 1800 ms the wave front reached the farthest offsets. If the reflector had been dipping, the wave front would have been non-concentric. If the reflector had been vertically each wavefront would have comprised two semicircles with different radii. The Exxon work was presented at the 1970 SEG Convention and appeared as a 1972 GEOPHYSICS paper'.

2. In the early 1970s GSI (at that time, a prominent geophysicalservice company) developed Seiscrop, a method for displaying areal views of seismic data volumes. Inspired by Exxon's presentation, GSI developed a time-slice approach that instead of slicing through seismic Instead of through processed 2-D seismic sections. Instead of wavefronts they displayed areal views of the reflections. In the 1970s digital technology was still fairly new, so the GSI researchers used the same display medium as the Exxon researchers time slices recorded on movie film. The display was in analog form on a Seiscrop table-the forerunner of today's interactive workstation.
Using 3D seismic and attribute analysis to track fluid movement in the subsurface
Authors: Luheshi M.N. , Ahsvihare S.G. , Evans J.
Published: October 2008

In 1993, there was a well control incident while drilling a prospect offshore Vietnam. This incidentnecessitated the implementation of an extensive seismic monitoring programme. It became rapidly apparent that conventional high resolution seismic techniques for identifying and monitoring gas in the subsurface were inadequate due to loss of signal power through the system.

This problem drove the need for an innovative approach to acquiring a 'Medium Resolution 3D Suwey'. This had two important characteristics, namely significantly higher bandwidth than conventional 3D data and also having the penetration necessary in order to image the target reservoir, through a disturbed overburden.

This paper describes the technology used in acquiring and processing the data, as this has relevanceto use of this type of acquisition for conventional reservoir description purposes. It also describes the attribute analysis developed to compare multiple vintages of seismic in order to be able to track fluid movement in the subsurface.

The enhanced resolution achieved has relevance to enabling better reservoir characterisation in general. The attribute analysis is an example of how these type of data can then be conditioned in order to allow tracking of fluid in the subsurface, in appropriate situations.

Introduction/background

Using seismic data to track fluid movement is a fairly well known technique, but one that still needs considerable development for routine use. In certain situations the rock properties of an interval change significantly enough to create a measurably different seismic response. [n order to apply this technology it is necessary to establish an understanding ofThe distribution of rock properties in the interval of interestThe scale of the change in seismic response caused by different fluid fills (water, oil, gas)Whether the quality of the available seismic data has the amplitude, time and depth resolutions required to detect these changesAnd, for monitoring cases, whether the quality of the seismic is controlled sufficiently to enable comparisons between successive surveys

In the case presented here, the interest was in monitoring possible subsurface gas movements following a well control incident. The technical problems and the approach, however, are quite generic; in that the same principles apply for fluid monitoring experiments in conventional production situations.

For the particular problem presented here, it was necessary to establish the history of gas movement in the subsurface using a series of seismic data sets which had different acquisition and processing histories. The need was to understand to what extent it was possible to measure the extent of gas charged sands using these seismic data sets.
The Use of Exploration 3D Data in Geohazard Assessment: Where does the Future Lie?
Authors: Hill A.W.
Published: October 2008

Increasing use is being made of exploration 3D datssets in geohazards evaluations. This new attitude towards the use of exploration data has occurred whilst operators have been revising all their oilfield working practices. The streamlined approaches to exploration through to development have required site investigation practices to be refined to allow business plans to maintain the speed and momentum of their projects whilst ensuring safety. Using explorers's 3D data to screen potential well or platform locations or even pipeline routes the Site Investigation Specialist can ensure that inappropriate locations or routes are not surveyed whilst minimizing survey costs.

Introduction

3D seismic data is not a new phenomenon. The 3D seismic approach has been available to the explorationist for over 20 years. Originally its cost and the length of time it took to process the data meant that the approach was perceived to be of use only to field development and not the exploration phase of prospect evaluation. However, over the last four years there has been a revolution in the turnaround time of 3D data from completion of acquisition to arrival of data for interpretation on the workstation. Whereas turnarounds were previously ofien greater than one year before arrival of first pass processed results, delivery is now regularly within four months of thefinal shot being fired. At the same time the reduction of unit acquisition costs have made the use of 3D data more attractive for use in initial exploration prospect identification. The latter aspect has been largely brought about by the breakthroughs in acquisition approach. Surveys are now being regularly acquired with eight or more streamers allowing ever greater acreage to be covered by 3D surveys faster than ever before and at a lower unit cost.

This is well demonstrated in the west of Shetland arena of the UK continental shelf. Irr the beginning of 1990, althoughthe area had seen exploration activity for at least ten years, not one single 3D survey had been acquired. By the end of 1992 only two small 3D surveys over the Clair Field, totalling only 440 square Kilometres, had been acquired. 1993, however, marked a watershed. [n 1993 the number of streamers being towed on 3D surveys began to increase dramatically, this coincided with the 'faster - cheaper 3D' demands of the operators. It also coincided with a surge of renewed interest in the West of Shetland area. The result is that by the end of 1996 some 15500 square kilometres of 3D data will have been acquired in the area

However, this explosion in 3D data coverage is not special to this area of the UK continental shelf. The story is repeated across the North Sea and especially in the Gulf of Mexico where either proprietary or speculative 3D datasets provide almost blanket coverage.