bluuebunny/crossref_metadata_2025 huggingface dataset:
Installation of a Production Manifold in 2000 ft Water Depth Offshore Brazil
Authors: Roveri F.E. , de Oliveira M. , Moretti M.J.
Published: October 2008

This paper describes the installation and related analyses of a subsea production manifold in 620 meters water depth at Campos basin, offshore Brazil. A pre-installed mooring system was used to moor the crane barge which lowered the structure.

Time domain and frequency domain computer programs were used to evaluate the response of the system A sensitivity study was conducted in order to assess the added mass, damping, stiffness and excitation forces influences on the system response and the importance of such parameters in the computer model calibration is discussed.

Model tests were performed in order to determine the manifold hydrodynamic coefficients to be input to a computer program to evaluate the displacements and forces during the descent of the structure. Offshore measurements were performed on the hoist forces, vessel motions, crane boom tip vertical motions and manifold vertical motions. The anticipated responses are compared with some of these measurements. The method used for lowering the manifold, the mooring system and the manifold orientation and positioning system are described. The design and installation strategy considered to adapt a conventional crane barge for installation beyond its nominal specifications, but considering safety and cost-effectiveness, are also described.

Introduction

In December 1995 the DL-2 production manifold was installed in 620 meters water depth at the Albacora field on the continental slope at Campos basin, offshore Brazil. The contract for fabrication was granted to a Brazilian company and the operator of the field, Petrobras, undertook the installation of the manifold through its owned 122 by 30.5 by t3.5meters pipe lay and crane barge BGL-1, The structure was first loaded out on 18* of November onto the deck of Petrobras transportation barge BS-5, transported to BGL-1 inshore and then lifted by BGL-1 crane and sea-fastened to the crane barge deck. The manifold was landed on the sea bed on 19th of December.

The manifold dimensions are 19 m by 14.5 m by 7.5 m high and it weighs 4120 kN in air, which includes a foundation substructure, the manifold itself and a installation lifting tool. Shallow foundations were adopted and four 40 m2 footings were utilized to provide the required bearing capacity. For details about the functional features of the manifold please see OTC paper 8236.

The seabed has a 5 degrees slope and the substructure was built so as to have the mudmats at the same inclination. The manifold had to be landed within +/- 10 degrees in heading, in a target area with 10 meters radius and within +/- 2 degrees in leveling. Should the later not be achieved, the manifold leveling system would be used. In this case anothervessel with drill pipe handling capability would be required.

Installation planning

The installation alternatives considered for lowering the manifold involved a drilling rig, a dynamically positioned crane vessel and a conventionally moored crane barge.
Further Advances In Deepwater Flowline Connection Technology
Authors: Moreira Jose Roberto , Cerqueira Maxwell B. , Silva Geraldo Rosa , Nagle Fernando J.
Published: October 2008

A diverless guidelineless flowline connection system, the so called direct vertical connection, has been developed, and tested, which sharply decreases connection time, while allowing the layvessel itself to perform both flowline ends connections, thus dispensing with the use of auxiliary tools and making the operation more cost effective and reliable.

This system has been designed to overcome problems associated with conventional pull-in systems, the lay-away method, ROV assisted pull-in systems and 'conventional vertical connections'. The former have already been successfully used in Marlim field, in 25 wells located at water depths ranging from 740 m to 980 m.

The direct vertical connection can now be considered a field proven method. Five import flowline connections have already been successfully performed in Albacora field manifold, installed at 620 m water depth. From now on, based on the excellent results achieved from those installations and previous tests, all deepwater Brazilian subsea trees and manifolds will be designed for direct vertical connection. Sixty six trees and six manifolds incorporating the direct vertical connection system are presently under fabrication in Brazil.

Introduction

A significant aspect which must be considered in developing subsea systems for the production of hydrocarbons in very deepwater is the connection of the flow lines to both subsea trees and manifolds.

Field experience learned from the installation of the first diverless trees offshore Brazil, showed (ref. 1) that conventional pull-in systems were subject to a wide failure mode range and almost always required diver assistance, although designed for diverless operation, Only one out of29 pull-in trees was installed without any diver assistance in Campos Basin, which is, by far, the most prolific Brazilian basin and where all deepwater fields are located.

Fortunately, at that time, subsea wells offshore Brazil were not located at water depths out of divers' reach and the problem was solved simply by using diver assisted trees instead of 'diverless' trees. It is worth mentioning that the former proved to be less diving-time consuming than the latter. However, new discoveries located at water depths beyond 300 m (limit diving depth) have obliged us to face the challenge of designing a reliable diverless flowline connection.

The lay-away system

Instead of attempting to improve existing pull-in methods, an important decision was made: to adopt the lay-away technique (ref. 2), which was devised by Petrobras engineers. The primary objective of the lay-away system is to provide a means of running either tree or production base attached to the flow lines in order to prevent the vulnerable pull-in operations.

So far, 57 lay-away operations, including 36 guidelineless operations, have been successfully conducted in Campos Basin in water depths ranging from 287m to 1027m.
Experience from first 100 Tie-ins at Troll Oil
Authors: Halle Per Olav
Published: October 2008

1.0 ABSTRACT

New, diverless tie-in equipment have been designed for the Troll Oil Field in the North Sea. Since 1992, engineering manufacturing and testing have been done to achieve safe, simple and reliable offshore installation, The first pull-in and connections offshore were performed summer 1994. Summer 1995 approximately 100 diverless flowline and umbilical tie-ins were performed. In September 1995. the Troll Oil were set into production. This paper gives some of the experience rom the extensive offshore tie-in operations using the Troll PICT (Pull-In and Connection Tool).

2.0 INTRODUCTION

2.1 Troll Oil Field Development

Troll oil is part of the huge Troll field. which is one of the largest gas fields offshore in the world. Troll is located near the west coast of Norway. The water depth is 325 m (1000 R). Below the gas there is a thin oil layer. By using horizontal drilling this oil is produced from the Troll B platform by Norsk Hydro. The gm is developed from Troll A platform by Norske Shell. To produce the oil the gas pressure is required. Troll Oil project had to be developed fast and with a lot of wells spread out in a wide area.

The subsea production system consists of 22 single well satellites tied back to four 6-slot and one 8- slot manifolds with gathering lines via 2 riser bases to the floating production unit (Troll B). Between the satellites and the manifolds there are one 6' or 8' flexible flowline and one steel tube integrated service umbilical (lSU), etween the manifold and the Troll B (here are 2 × 9' or 2 × 10' flexible gathering lines and one main ISU. All gathering lines are connected at the riser base to dynamic risers. The design pressure for gathering lines and flowlines are 3000 psi.

2.2 Troll Oil Tie-in System Development Schedule

The design of a combined pull-in and connection tool started back in 1991 based on the experience gained on the Troll Oseberg Gas Injection Project (TOGI). Late 1991 basic engineering studies were performed at TrollOil for the operator Norsk Hydro. Summer 1992 the tie-in contract were set out. Testing of the first Pull-in and Connection Tools (PICT) started summer 1993 which were followed up by system test tie-ins at the Production Riser Base, Manifold Centres and the Satellites/Pernlanent Guide Bases. Summer 1994, first tie-in operations offshore were performed, but the bulk work were done summer 1995. Production starl up of the field was 20. September 1995. The tie-in operations will continue 1996 until all wells are tied-in. Total of 160 connections have so far been manufactured.

3.0 TIE-IN SYSTEM DESCRIPTION

3.1 Main Equipment

The tie-in system consists of the following main equipment:3 Pull-in and connection tools (PICT)2 lntenension Control Systems (lCS)2 set Umbilical and pull-in wire surface winches160 Cli]mp connectors with assorted seal plates and seals
Numerical Test Tank: Simulation of Ocean Engineering Problems by Computational Fluid Dynamics
Authors: Ortloff C.R. , Krafft M.J.
Published: October 2008

With the increase in knowledge in computer-based simulation methods and recent advances in high-speed computing, solutions to complex fluid-structure interaction problems, such as transient wave impact on fixed and floating structures, can now be studied in more detail. Numerical results, combined with model test measurements for verification, form the basis of the concept of the Numerical Test Tank (NTT) concept. Sample results of the application of Computational Fluid Dynamics (CFD) methods to the solution of two important ocean engineering problems are presented to illustrate the present methodology, and are then compared to model test results.

Specifically, CFD solutions are obtained for green water impact on a full-scale, FPSO hull and deck structure. The present numerical method employs a fully three-dimensional, transient, viscous Navier-Stokes solver based on the FLOW3D/ 96 CFD code. The results of the simulation are shown to produce at least qualitative agreement with model test results with respect to the shape of the incident, reflected and on deck- transient surface wave profiles. Some differences between the simulation and test results arise due to details of the simulation set-up, such as cell sizes, cell distribution, convergence criteria, turbulence model, and boundary conditions.

Additionally, CFD methods are used to compute current force coefficients for a scale model of a 200,000 DWT tanker. Computed force coefficient values are Froude-scaled and compared to OCIMF recommendations, which are based on Froude-scaled model test data. Preliminary CFD results indicate basic agreement with OCIMF data, however future computations of coefficients for a full-scale hull, and further analysis of test data will be necessary in order to investigate viscous scale effects in more detail. The apparent utility of the Numerical Test Tank, as illustrated by the example solutions presented, indicates that this computational approach holds promise for improving detailed knowledge of design loads for fixed and floating structures subject to severe wave and current loading.

Introduction

The design of FPSO systems for harsh wave environments often requires model testing of green water impact on deck structures. In 1993, SOFEC conducted 100-yr survival tests of the 140,000 DWT FPSO for AOPC's Liuhua field at MARINTEK; Figs. la, 1b and 1c show a typical sequence of on-deck green water flow and impact. During these tests, a limited number of instruments were used to determine impact loads on the turret surround structure and the breakwater protecting the process modules. The measured loads and volume of water which passed over the breakwater were sufficiently large so as to warrant a second set of green water tests at MARIN (Fig. 6). These tests were specifically designed to study wave impact and breakwater optimization. In September 1996, typhoon Sally passed within 10 nautical miles of the Liuhua FPSO, generating waves (88 feet) and winds (112 knots) associated with a 200-yr event.
The Mars Project Overview
Authors: Godfrey D.G. , Haney J.P. , Pippin A.E. , Stuart C.R. , Johnston D.D. , Oriean R.H.
Published: October 2008

The Mars Project is a $1.0 billion investment in a record breaking water depth of 2940 ft. in the Gulf of Mexico. As Shell's second Tension Leg Platform (ILP), it incorporates lessons learned from designing, constructing, and operatingShell's first TLP Project, Auger. The Mars TLP is a 53,000 ST displacement floating structure supporting full drilling and production facilities. Oil and gas are exported via 18- and14-inch pipelines, respectively, to a pipeline hub platform at WD-143. The design and contracting approaches for the Mars TLP were significantly affected by the need to improve project economics through cost reduction and schedule reduction. Thisresulted in an emphasis on topside payload reduction, a fit-for-purpose approach, elimination of components through innovation, overlapping design and fabrication activities, elimination of a hull design cycle, and a risk-sharingcontracting strategy. Design, fabrication, and installation of the Mars TLP was approximately $65 MM under budget and 3 months ahead of the approved schedule. This was an improvement on the Auger TLP results by more than $200 MM and I 1/2 years. The Mars approach to TLP design andcontracting has continued on Shell's ongoing Ram/Powell and Ursa Projects, with some adaptation based on Mars experiences.

Introduction

This paper is the first of 6 papers presented at a special session of the 1997 Offshore Technology Conference dedicated to the Mars Project. It is an overview of the project that ties the individual papers together. For detailed information, the reader is referred to the other five papers presented at this special session.

General Information

The Mars prospect comprises portions of six OCS leases in the Mississippi Canyon Area, located 130 miles southeast of New Orleans in 2940 ft. of water. Shell and BP Exploration are jointworking interest owners with 71.5% and 28.5%, respectively, and Shell as operator. The discovery well was drilled on Block 763 in 1989 by the Discoverer Seven Seas drillship. A total of five wells and five sidetracks were drilled from 1989 through 1991. The results of the drilling programs, 3-D seismic interpretation, reservoir simulation, and probabilistic cost estimates for various development systems led to selection of a TLP for field development in October 1992 and projectapproval in September 1993. Shell's current assessment of total gross ultimate recovery is about 500 million barrels oil equivalent from this phase of development. A future development phase is possible and could increase reserves to about 700 million barrels oil equivalent. The reservoirs at Mars are geopressured turbidite sands containing under saturated oils with an average GOR of 1,000 SCFIBBI. The API gravity ranges from 20 to 32° and sulfur content is 2-2.5%.

The Mars TLP has the capability to support 24 wells of which 10 were predrilled by the semi-submersible drilling rig. George Richardson. The remaining wells will be drilled fromthe TLP by the H&P 201 platform drilling rig.
Neptune Project: Spar Hull, Mooring and Topsides Installation
Authors: Kocaman Alp , Verdin Earl
Published: October 2008

This paper describes the installation of the Neptune Spar at Viosca Knoll Block 826, approximately 90 miles south of Mobile, Alabama in the Gulf of Mexico. Water depth at the project site is approximately 1,930 feet

The installation of the Spar was accomplished in two distinct phases. The first phase of the operations were completed about 3 months ahead of the arrival of the Spar hull at site. Inthis phase, the six anchor piles were driven and the six mooring lines were laid on the sea bed.

In the second phase of installation operations, hull towout to the site, ballasting and upending of the Spar hull on location, the connection of the hull to the six mooring lines and setting the production facilities were accomplished. The Spar hull was towed to site horizontally and upended at site by selectively ballasting hull compartments. The mooring lines were then attached to the hull. The mooring lines are a combination of spiral strand wire and chain with a sea beddriven pile at the far end. The placement of the buoyancy cans inside the Spar moonpool area (center well bay) which support the production risers, then completed the installation effort.

Introduction

The Neptune Spar hun construction was started in February 1995, the Phase I of the installation work was completed inJuly 1996, and the Phase II of the installation work was completed in September 1996. The facility was turned over to the client in November 1996 and the first oil was produced in February 1997. roughly two years after the construction and installation contract signing. Reference 1 provides further details of the management of me contracting, construction and installation strategy.

The hull was constructed by Aker Rauma Offshore (Reference 2) in Finland in two sections and transported to a shipyard in the Gulf of Mexico in two sections. J. Ray McDermott was responsible for fabricating the production facilities, towing thehull to site. upending it, installing the mooring lines, buoyancy cans, export risers and the production facilities.

Both in Phase I and Phase II installation operations, J. Ray McDermott's dynamically positioned derrick. barge DB-50 was used extensively.

Being the first of its kind, a variety of options for each phase of the installation have been considered. The result of some ofthe work completed to date will be valuable to other Spar type floating production system designs.

Phase I Operations

Phase I operations consisted of the placement of the anchor piles. the bottom chain and the spiral wire on the sea bed.

Two flexible export risers were also installed following the mooring wire installation operation, however, the production riser installation operations are nm addressed here.

Piled Anchors

The initial design of the Neptune Spar mooring system was based on the principle of holding the Spar in place by using high capacity gravity anchors. A drag embedment type of anchor, most frequently found in semisubmersible drilling rigs, would be utilized.
Improvements in Design of Converted FPSOs Regarding 20 Years Operation Without Docking
Authors: Assayag S. , Prallon E. , Sartori F.
Published: October 2008

This paper presents improvements on basic and engineering design of four converted VLCCs that will be operated as FPSOs in Brazil's Campos Basin.

Conbersion of these VLCCs is under way, worked on by contractors around the world, the first of them being scheduled to start operations by the middle of 1997.

Project economics demand that the units be operated during the next 20 years without docking. PETROBRAS offshore operations and maintenance expertise were applied to achieve this goal, meeting unique FPSO operating conditions. Experience and data gathered by project team members and technical staff are now being incorporated into next generation units, which are at present moment in Design Basis phase.

Although these improvements will only show their effectiveness after units come into steady operation, we are confident that major achievements in safety and economics have been made successfully.

Introduction

The discovery of Marlim and Albacora, giant deep water fields in Campos Basin, offshore Rio de Janeiro state, will allow PETROBRAS, a remarkable increase in national oil production. On the other hand, due to the difficulties related to deep water production, distance from the shore and from existing facilities, the start of commercial production of hydrocarbons from those fields as quickly as possible, in the most economical way, within good reservoir exploitation techniques and preserving the environment is also an enormous challenge to the Company.

The traditional solution adopted by PETROBRAS for offshore production, the utilization of semi-submersible platforms (SS) as floating production units (FPS) and the pumping of oil and dispatching of gas by pipelines or the pumping of oil through monobuoy, was used in pre-pilot and pilot units in Marlim field (P-XI11 and P-XX), Stationary Production Unit (UEP) N.l in Marlim (P-XVIII), and in Albacora field (P-XXIV and P-XXV). Other units of the same type are planned, such as UEPs 2 and 3 in Marlim (P-XIX and P-XXVI).

However, in order to complete development of the fields, it would be necessary to expand the pipeline network, by the construction of new pipelines, or by the installation of new monobuoys, considered to be the "weak links" in the system, as the existing pipelines could not stand the increased flow. The technical and economical viability study shows as the best option, the installation of FPSOs. Due to the estimated field life of 20 years, and considering the complexity of the pull-in and pull-out operations, the study indicates the permanency of the units on location until the end of the life of the field, without docking.

The definition of the necessary storage capacity of the FPSOs took into consideration the estimated oil flows forecast for the fields, the availability of the tanker fleet to be used as relief vessels and, aiming to reduce operational costs, a lower frequency of offloading operations.

With PETROBRAS having some VLCCs available, the option of converting them into FPSOs came into consideration.
Twisted Base Jacket
Authors: Frame Malcolm
Published: October 2008

The design of jackets for supporting offshore oil and gas facilities requires extensive computerised analyses to demonstrate compliance with recognised codes of practice. To perform these analyses, software is available which requires from the user only the barest definition of the problem. The whole process of modelling the structure, sea loading and the non-linear response of the foundations can proceed automatically. This is followed by the mathematical solution of the problem, checks against the requirements of the code and re-sizing as necessary. A successful structure is represented as a list of stress ratios less than unity. Any reasonably well-conditioned, triangulated space frame can survive this process, but by its very nature it cannot ensure that the most efficient and economical jacket is thereby produced. By adopting the approach that the computer should only be used to verify a design whose basic form is determined by the application of simple basic rules of structural detailing, it becomes possible to regain control of the design process and to lead it towards an optimum solution. The adoption of this approach to design a jacket for quite specific service conditions has led to a new configuration which, in providing solutions to situations beyond the initial application, can be considered generic.

Introduction

The simplicity and evident economy of early jacket designs for shallow water are desirable features to retain when such structures are developed for deeper water and more onerous service conditions. In the North Sea, this development was accompanied by a change in the installation method from lifting to launching, and the basic structural form was so drastically modified that continuity with shallow water designs was not appropriate. The subsequent development of derrick barges with crane capacities sufficient to lift-install jackets which hitherto had been launched makes it possible to reestablish this continuity. However, to a very large extent, liftinstalled jackets for deep water were developed from their launched predecessors, rather than from shallow water lified precedents which, in principle, should provide a more fruitful starting point. This paper will show the development of a jacket design which is based on a shallow North Sea structure, but extended so it can operate at the limit of a deep-water jack-up drilling rig (about 100 metres), and can then be further stretched to even deeper water. When the jacket is stretched so that it can no longer be lified using available derrick barges, the design lends itself to piecemeal installation without extensive modifications, the size of each piece being varied to suit the available lifting capacity.

Properties of Shallow Water Jackets

Fig. l(a) is a side elevation of a typical jacket suitable for a water depth of, say, up to 40m. The legs are vertical and spaced on a square pitch of 20-22.5m. It probably carries a deck weighing 500- 1000 tonnes and supports 5–10 well conductors which are accessed by an adjacent jack-up drilling rig.
Hibernia: Pioneering a new frontier
Authors: Smith Harvey A.
Published: October 2008

Hibernia is the pioneer development for the emerging Canadian east coast offshore oil industry. As the first operator in this area, the Hibernia Management and Development Company Ltd. (HMDC) is developing local skills and infrastructure which can support future developments. The Hibernia field is located 315 kilometres east southeast of St. John's, Newfoundland. It consists of two reservoirs - the Avalon and the Hibernia reservoirs, located at average depths of 2400 metres and 3700 metres respectively. Containing approximately three billion barrels of oil in place, Hibernia is the fifth largest discovered oil field in Canada. Recoverable reserves are estimated to be 615 million barrels. Limited data is available on the Avalon reservoir at this time, and initial drilling activity is expected to identify significant reserves upside. A fixed drilling and production platform is being assembled in Newfoundland to produce the field. Its design includes a first-of-its-kind concrete Gravity Base Structure, which has a 15 metre thick ice belt that can withstand the impact of multi-million tonne icebergs. The completed platform is scheduled to be towed to its offshore location in June 1997, with first oil expected in December. The platform has a design production capacity of 150,000 barrels of oil per day. Average production of 135,000 barrels of oil per day is expected during the 6 year plateau period. Other discoveries around Hibernia offer the opportunity for subsea tiebacks for processing and storage of crude in the future. Hibernia has a pre-production budget of US$4.4 billion, and total development costs are estimated to be US$8.0 billion, excluding transportation costs.

Introduction

The waters off the east coast of Newfoundland are host to 16 undeveloped oil fields containing estimated recoverable reserves of 25 1 million m3 (1.6 billion barrels). The area also contains an estimated 234 billion m3 of gas, and 58 million m3 of natural gas liquids1. With oil in place estimated at 477 million m3 (three billion barrels) and recoverable reserves of 98 million m3 (615 million barrels), Hibernia is by far the largest discovery offshore Canada to date. In fact, it is the largest undeveloped oilfield in Canada, and by the turn of the century is expected to produce approximately 10% of Canada's light crude oil production. Once Hibernia begins production in December 1997, it will be leading the development of a new offshore oil industry for Canada.

However, one field does not constitute an industry. In order for an industry to evolve, Hibernia has to prove that it can compete with similar operations by achieving its goal of top quartile industry performance in relation to the North Sea. This goal is achievable but will present challenges, especially in the area of platform support costs.

Using present day technology, it will take 18 years todeplete the estimated 98 million m3 (615 million barrels) of recoverable oil from the Hibernia field.
Heave Compensated Landing System - A Novel Tool for Subsea Intervention
Authors: Nelson Ron , Soliah James , Caldwell Trevor , Morrison Denby , Pritchard John
Published: October 2008

This paper presents a new intervention system that allows the use of a low cost workboat to deploy and recover delicate payloads in subsea installations. Vessel motions are decoupled from the subsea package by a specific chain and buoy system. A prototype was built and successfully tested offshore in 3,000 ft of water during May 1996. The Heave Compensated Landing System (HCLS) concept, offshore testing program, test results, lessons learned, and future developments are discussed.
Research Issues in the Repair of Composite Structures
Authors: Donaldson S.L. , Song J.Y. , Roy A.K.
Published: October 2008

The composites repair in the past was mostly for nonstructural applications. For the present emerging systems and to extend service life of structural members, repairs need to be made at the structural level. Several issues that are imuortant to bonded composite repair and its performance in realistic environmental conditions are discussed, Some of the recent work performed at the Air Force Materials Directorate is presented. The effects of surface preparation and laminate stacking sequence on strength of double-lap shear specimens are described.

Introduction

The Air Force maintains a number of composite aircraft, and these numbers will increase in the future. Maintaining these aircraft will require extensive repair of damaged composite structures during their operational lifetimes. AS a result there is an urgent need for developing durable and cost effective repair methodology. The existing repair techniques usually use monolithic or composite materials as patches. doublers. etc., which are applicable for the repair of secondary structures and for small strain levels. But the present advanced aircraft, e.g., F-22, B-2, use a significant amount of composite structural parts and operate at higher strain levels. In order to maintain these advanced aircraft, there is a need to develop repair methodology for significantly higher strain levels.

The bolted and bonded repairs are both feasible repair techniques. But, the bolted joints in general weigh more than the bonded repair, and the holes created for the bolts also cause undesirable stress concentrations in the parent structures. Due to the availability of high performance and damage tolerant structural adhesives, the bonded repair is preferred over bolted. Thus issues related to the bonded repair will be emphasized and addressed in this project.

Research Issues

The structural performance of a bonded joint repair greatly depend on the performance of the adhesive that is used in the joint. The durability, damage tolerance, environmental effects, thermo-mechanical fatigue performance, etc. of a bonded joints are not yet well investigated. Of particular concern is the combined effects of repeated moisture exposure and drying cycles, in conjunction with thermal spiking and mechanical loading. Quite often repair (patching) requires to be performed in the field and on aircraft. The equipment availability in field repair is different from that performed in depot. But large and structurally reliable repair in the field must be performed to reduce down time of aircraft.

In the past repair used to on nonstructural parts, often small and easy to do. For the emerging aircraft systems and to extend life of existing aircrafts, repairs need to be performed on structural members and the repaired part should be able to reliably perform around a strain level of 5000 microstrain. As a result, there is a need for new repair materials, processes, analyses, and nondestructive inspection (NDI) techniques
Feasibility Study of a Dual Density Mud System for Deepwater Drilling Operations
Authors: Lopes Clovis A. , Bourgoyne Adam  T.
Published: October 2008

Recent successful exploration efforts in deep waters have heightened interest in-developing oil and gas reservoirs on the continental slope. Leases have been obtained in water depths up to 10,000 ft with a requirement that they be drilled within the next decade. Use of current techniques to drill these leases will require extremely large floating drilling units and large diameter marine riser systems. This paper presents the results of a feasibility study of the use of an automated gas-lift system for a marine riser that will maintain the hydrostatic pressure in the subsea well-head equal to the hydrostatic pressure of the seawater at the seafloor. Hydrostatic control of abnormal formation pressure could still -be maintained by a weighted mud system that is not gas cut below the seafloor. Such a dual density mud system could reduce drilling costs by reducing the number of casing strings required to drill the well and by reducing the diameter requirements of the marine riser and subsea blowout preventers. The system would have the advantages of riserless drilling without giving up the well control advantages of a closed, weighted mud system.

A steady-state numerical model was developed that can be used to determine the gas injection requirements needed to achieve a desired dual density configuration. The numerical model was verified through tests conducted in a 6,000 foot research well. Once verified, the model was used to define the gas requirements and practical limits of a marine gas-lift system based on estimated additional costs of gas compression and nitrogen membrane filters. The practical limits are presented in terms of maximum mud density, water depth, and riser diameter combinations. The paper also discusses the operational changes that would be required for various drilling procedures such as making a connection, running casing, kick detection, and well control operations.

Introduction

Drilling operations in waters deeper than 3,000 ft are increasing throughout the world, and the industry is now looking into the challenges imposed by ultra-deep waters (>7,000 ft).

One of these challenges comes from the fact that the current technology relies on the use of marine risers to extend the well up to the drilling vessel, so the mud and tools can get in and out of the well in much the same way that is done on land However. when drilling with mud densities in excess of sea water density, the exposed sediments in the open borehole see a pressure tending to cause formation fracture that is affected by the full column of drilling fluid all the way up to the drilling vessel. The overburden pressure of the sediments tending to help resist formation breakdown is generated by sediment densities in excess of seawater hydrostatic only from the mud line down.
The Challenges of Lufeng 22-1 Development
Authors: Millmaker Allan , Yu Liang , Adlam John
Published: October 2008

1.0 ABSTRACT

This paper describes the challenges involved with the development, design and fabrication of the FPSO and related facilities for the development of the Lufeng 22-1 field.

The field will be developed using five subsea wells connected to the FPSO by two flexible flowline risers. The five horizontal wells will be drilled through single template and completed with subsea production trees mounted with electrically driven booster pumps, installed to provide the means of artificial lift.

The FPSO is based on a multipurpose shuttle tanker (MST) fitted with a processing plant which has a capacity of 125,000 bpd of gross fluid volume, and 60,000 bpd of crude oil. The storage capacity of the vessel is 640.000 bbls. The individual well rates are expected to reach 25,000 bpd of fluid and 15,000 bpd of oil.

The Lufeng crude oil is paraffinic, low sulphur with a high wax content. The API gravity is 31.1" and the pour point 43°C requiring the oil to be stored at elevated temperature above wax appearance temperature of 62°C. The mooring system is a Submerged Turret Production (STP) system which is disconnectable in extreme weather conditions.

2.0 INTRODUCTION

Lufeng 22-1 is a small oil field located remote from existing infrastructure in the Pearl River Mouth basin in 333 meter of water approximately 265 km Southeast of Hong Kong in the south China Sea. See figure 1 - Lufeng 22-1 Location.

The field, owned by Statoil (75%) and CNOOC (25%), was discovered in 1986 and two further appraisal wells were drilled in 1989. Extensive testing was performed on the appraisal wells with rates of up to 24,000 bpd achieved and approximately 1.6 mmbbls of oil produced. The tests confirmed the high porosity of the sandstone reservoir and indicated the need for horizontal well technology to delay water influx and maximise oil recovery. The field is being developed with five horizontal wells with horizontal section lengths between 480 and 1800 meters.

The field is marginal with considerable uncertainties in the reservoir production parameters. The anticipated costs of a conventional stand alone development do not make the field economically viable and alternative model was therefore required.

The oil reserves to be recovered are estimated to be ca. 30 mmbbls representing a recovery factor of approximately 25% of the original oil in place. The environmental conditions in the South China Sea also contribute to the difficulties experienced by potential field developments in the area. Typhoons are frequent and the area is affected by solitons (subsurface waves generated by tidal variations).

The system chosen to develop the field is an FPSO based on the multipurpose shuttle tanker MST Munin. Facilities are provided on day rate lease. See figure 2 - Lufeng 22-1 Field Development Arrangement.
Vertical Connection Used as Tie-in System for Rigid Pipeline
Authors: Moreira C.C. , Puppim L.A. , Braga V.R. , Marins J.R. , Haugen F.
Published: October 2008

An attractive alternative to the use of flexible pipe flowlines is the use of rigid pipe flowlines. This is especially true in deep water giant fields or marginal fields, where the distance from floating production units to the wells is often several kilometers.

Deepwater diverless tie-ins have a significant impact in the overall economics of the field development, and the selection of the tie-in method is a part of the critical path.

This paper describes the studies conducted to evaluate and select a diverless tie-in system for the connection between the manifolds and rigid pipelines, and between rigid pipelines and flexible risers.

Introduction

In previous developments of deep water fields in the Campos Basin, Brazil, in water depths up to 1000 m, flexible flowline between christmas-trees or manifolds and floating production units have been used as a standard. The use of flexible pipelines allowed for rapid development of new fields, and the ability to recover and re-use flexible pipelines reduced their capital cost. Several connections systems has been used, including horizontal pull-ins, lay-away installations, and most recently the Vertical Connection System(VCS), addressed in ref. 1.

Field development in Brazil is now moving into deeper waters and more marginal fields, requiring longer flowlines. As the flow line length increases the cost effectiveness of flexible pipelines is reduced when compared to rigid pipelines. In a new scenario of Albacora field, two(2) subsea production manifolds will be connected to rigid pipelines.

Nating in flexible risers. The use of rigid pipelines requires a new diverless connection system to be selected.

To evaluate alternative tie-in methods for rigid pipelines at the manifolds and risers, a study was performed to select the most economical and feasible tie-in system. Consideration was given to the resources available in Brazil, the operational experience and the technical soundness of the system, and the ability to meet the project schedule and budget

Scenario

In Albacora Field - phase I1 (fig. l), four (4) subsea production manifolds and one (1) subsea water injection manifold will be tied in to the production unit, the FPSO P-3 1 Vidal de Negreiros.

Each production manifold will receive the production of eight (8) wells. The schematic of the production manifolds (fig. 2) shows the following:One (1) 8" ID production header,One (1) 8" ID service header,One (1) 4" ID production test header,One(1) 4" ID gas lift header.

To allow pig passage (required to prevent paraffin formation) the production header and the service header are connected in a pigging loop, as well as the production test header and the gas lift header.
External Acoustic Sensors and Instruments for the Detection of Sand in Oil and Gas Wells
Authors: Brown Gerald K.
Published: October 2008

From the earliest days of oil and gas production, solids mixed with the flowing medum have caused problems. The origins of these solids (sand) can be attributed to formation particles, solids introduced into the well such as drilling mud and frac sand, corrosion products (metal loss) and any other solids flowing through a system. With the ever changing methods of well drilling and completion the probability of sand is much higher today. In addition, the financial payback time is shorter so that more flow must be attained in a quicker and shorter time frame.

If the production of sand is not minimized, formation damage can occur, downhole well equipment can be damaged, surface production equipment can be damaged and plugging of surface equipment can occur. The damage to the equipment alone can be expensive as well as the loss of product during downtime. In addition, the possibility of failures due to sand erosion can be catastrophic as produced fluids and gases can escape into the land, sea or atmosphere when a failure occurs due to erosion.

There are many methods of sand control. In order to control the sand production it is necessary to have an early indication of the sand flow and its intensity. This paper will give a brief overview of the history of sand monitoring and the latest technology available for the detection of sand and the detection of the damage (erosion) that sand can cause.

Introduction

In the production of oil and gas a borehole is drilled through to a strata of rock that has enough porosity to allow the flow of liquids and gases from the rock into the borehole. This liquid or gas, or combination of liquid and gas, then flows, or is pumped up, through the borehole to the surface.

Solids mixed in with the produced fluids and gases indicate that either the formation is breaking down or other solids such as fractionation solids, drilling mud, construction debris, scale, or corrosion products are flowing up the well bore. In any case this flow of sand is undesirable.

Breakdown of the formation can lead to unstable flow and formation damage that can eventually lead to loss of production and even abandonment of the well.

When other solids are flowing with the product we usually see an initial heavy flow of solids in a new well as these solids introduced as a result of drilling, formation fracturing, cementing, and production completion construction that have accumulated in the well bore flow to the surface. Once the initial amount of solids are clean from the well, the flow of solids is usually stabilized until such time as the well is adjusted to flow at such a high rate that the solids from the formation (sands) break loose and flow up the well bore. In addition, after a period of time produced scales and corrosion products can also flow to the surface.
Campos Basin: 20 Years of Subsea and Marine Hardware Evolution
Authors: Formigli J. , Porciuncula S.
Published: October 2008

Since 1977, when the first oil was produced to a floating rig through a test tree inside the BOP Stack (Enchova-01 well), around 30 Floating Production Systems were installed in Campos Basin, offshore Brazil. Due to the prolific geological conditions of this province, production ranges from shallow (100m) up to deep waters (1027m), demanding significant breakthroughs in the applied subsea and marine production equipment which were used for the exploitation of these fields.

This paper presents the technical evolution of the associated hardware, as manifolds, umbilicals, flowlines, monobuoys and mooring systems, highlighting some milestones which made viable the achievement of the present water depth limits of oil and gas production. Their field performance is also shown and gives a real solid background for the extension of the water depth limits up to 2000m for future production systems under design/construction, not only in Campos Basin but also for other offshore sites around the world.

Introduction

Campos Basin is located offshore Rio de Janeiro State, on the Southeast Region of Brazil. Its area covers approximately 100sq. Km ranging from 20m up to 3400m Water Depth (WD).

Environmental conditions can be considered as relative "benign"; 100 year return period conditions are:wind: 37mls;waves: 14m height/l2s period;surface current: 2.0m/s;bottom (1 000m WD): 0.8m/s.

The continental shelf may be described as a flat surface with a very slight inclination (constant gradient around l°) up to water depths around 200m. Beyond this border, the gradient increases gradually up to values around 10° or more in some locations, featuring the so called continental slope. Ocean floor is generally smooth all over Campos Basin but some local canyons in water depths ranging from 400m till 1500m are outstanding. Clay sediments are predominant at the mud line with dispersed occurrences of live and dead deep water corals.

The first field discovered at Campos Basin was Garoupa in 1974 through the wildcat 1-RJS-9A; in a short period of time, Namorado and Enchova fields were also discovered: these were the former evidences this area could be a prolific oil province. Based on this assumption, it was necessary to improve the exploratory efforts. At the same time, Brazilian political and economical situation demanded a significant increase in the domestic oil production using the fastest pace as possible.

The traditional conception to produce fields with similar characteristics - a stationary jacket platform (eventually installed over a template with pre-drilled wells) - would demand more than half a decade for producing the first oil.