bluuebunny/crossref_metadata_2025_split huggingface dataset:
Design and Installation of Suction Anchor Piles at a Soft Clay Site in the Gulf of Guinea
Authors: Colliat J.-L. , Boisard P. , Gramet J.-C. , Sparrevik P. 
Published: October 2008

Abstract
Innovative shallow suction anchor piles have been used for permanent mooring of a process and accommodation barge at an oil and gas field developed by ELF Congo in the Gulf of Guinea. The 12 mooring lines, equipped with 5m diameter and 13m high steel suction anchor piles, were successfully installed at the site in July/August 1995. The process barge is scheduled to be connected early 1996 for start of production. With a water depth of about 170m, the Nkossa field is the deepest in offshore Western Africa to date. The soils at the site consist of soft normally consolidated clays, representative of deep water sites. The anchoring system design is presented, together with the description of the suction pile installation by under pressure. The monitored performance of the suction piles during installation is evaluated, including orientation and tilt at touch-down, and penetration rate during suction penetration. The installation behaviour appeared to be very smooth, and the measured penetration resistances were in perfect agreement with the predictions, thus demonstrating the reliability of the design installation method.

Introduction
The suction anchor piles, penetrating into the seabed by means of creating an under pressure by pumping out the water entrapped inside the caisson, are found as 'buckets', 'skirted foundations' or 'suction anchor piles' in the literature. The principle was first introduced by Senpere and Auvergne (Ref. 1), as alternative anchor for mooring a storage tanker at the Germ field offshore Denmark. More recently, and because of its and reliability, this foundation concept has renewed interest in the offshore industry, simplicity found a both as foundation for fixed platforms and as mooring anchor point. In addition to the Germ tanker mentioned above, mooring systems with suction anchor piles have been installed at three different sites in the course of the summer 1995, at Harding and Yme fields in the North Sea, and at Nkossa field offshore Congo.
The Nkossa oil and gas field presently developed by ELF Congo is the deepest field in the Gulf of Guinea to date, with a water depth ranging between 150 and 300m. It includes two steel jackets (installed early 1995) with tender-assisted drilling, one process and accommodation barge (scheduled to be at the site early 1996 for start of production), and two floating storage and offloading tankers, one for oil and one for LPG (see Figs. 1 and 2).
The design of the anchoring system for the process is given in the paper, together with the description of the suction anchor pile installation, with an emphasis on the monitored performance of the suction piles during installation.

Barge and Site Characteristics
Process Barge, The process and accommodation barge to be installed at the Nkossa field is presently under hookup and commissioning in South of France, near Marseilles. The hull, 220m long, 46m wide and 16m deep, was built by Bouygues Offshore in high performance pre-stressed concrete.
Sour Gas Dehydration in Mobile Bay
Authors: Betts F.C. , Lay A.G. 
Published: October 2008

Abstract
An evaluation of Mobil's different methods of sour gas development utilized offshore and processes selected are presented with the maintenance history. The conclusions are based on field data showing past performance with a correlation made for future development and the selection criteria for dehydration

Introduction
Mobil's offshore operation in Alabama is divided into two main fields: The Lower Mobile Bay-Mary Ann Field and the Mobile OCS Block 823 Field.
The Mary Ann Field was the first Alabama offshore production and started in April of 1988. Located in state waters, the field spans the entrance and shipping channels 01Mobile Bay. The original field consisted of four producing wells, three production platforms and one auxiliary platform which served as a pipeline gathering facility.
The Mobile 823 Field is located southwest of Mobile Bay and south of Dauphin Island. This was the first production from OCS waters offshore Alabama and occurred during September 1991.
These fields have been designed, constructed, and produced independent of each other due to the gascompositions, rates, and timing. The average hydrogen sulfide content of the Mary Ann field is approximately 5 mol% while that of the Mobile 823 field is considerably less at approximately 150 ppm. Bottom hole pressures and temperatures of the wells differ with the higher values associated with the Mobile 823 field. Different methods for development have been chosen based on philosophy, operational requirements, and information which were available at that time. Now with the information and knowledge gained, all future production must go through a rigorous evaluation for the most cost effective method to produce and which system to incorporate that production.

Design Philosophy
The design philosophy for the Mary Ann field was based on the technologies available for that time period. The final design incorporated the cooling, separation and dehydration of the sow gas offshore to allow for the use of carbon steel materials for the surface and pipeline components. A corrosion inhibition system was also incorporated in the design to protect the carbon steel equipment upstream of the dehydration system and also to solubilize any element sulphur deposition which might occur on the platform.
Both glycol and desiccants were evaluated for sour gas dehydration with silica gel being chosen as the final design philosophy. The silica gel was chosen over other desiccants due to lower regeneration temperatures, less coking, and little or no carbonyl sulphide(COS) formation. The carbonyl sulphide formation had little to no affect for offshore, however this would have increased the sweetening unit load, the sulfur recovery unit, and the tail gas treater at the onshore plant. Some disadvantages noted of silica gel were the need for a regeneration media and the mechanical switching valves required for the cyclic service. Each of these added to the complexity of the desiccant operation and maintenance requirements.
Design, Construction, and Use of a Coiled Tubing Drilling Structure for Onshore and Offshore Operations
Authors: Frishmuth R.E. , Pursell J.C. , Middleton R.J. , Parker C.O. 
Published: October 2008

Abstract
This paper discusses the design, construction, and Initial application of a structure for supporting a coiled tubing injector head, bottom hole drilling assembly and pressurized lubricator. The paper includes a discussion of the features desired for the structure and how these were addressed during the design. The manufacturing of the support tower and its support platform are then discussed. On site assembly procedures for the movable structure are presented along with photographs of the deployed rig in service. The versatility and usefulness of the structure are discussed from the end users point of view.

Introduction
In early 1994, during planning for an effort to explore using coiled tubing for drilling operations, the engineers working on the development realized that a structure would be needed to support the weight of the drilling equipment. The objective of the drilling operation was to enter existing wells through the swab valve on the top of the Christmas tree and, while under pressure and blowout prevent (BOP) control, drill laterals into new pay zones. Hence, the BOP was to be mounted on top of the Christmas tree along with a lubricator long enough to contain the entire bottom hole assembly (BHA) and strong enough to contain well pressure. The coiled tubing injector head and pack off would need to be mounted on the upper end of the lubricator. The mechanics of this operation requires that long and heavy pieces of equipment would have to be held vertically over the well with the coiled tubing injector head located at the very top of the equipment stack. It was recognized that a unique and portable structure was needed to hold the coiled tubing drilling equipment. Thus, CAMCO, with the agreement of British Petroleum, a major partner in the drilling project, began a program to design and construct a support tower and a platform on which to locate the tower. This paper is a report on the various phases of the design, construction, and deployment of the drilling structure (DS).

Design Requirements
The primary purpose of the DS is to prevent bending moments and undue compressive loads from being transmitted to the wellhead while permitting the entire BHA to be lubricated above the wellhead and BOP's. This required that the tower had to be rigid enough to prevent the injector head from moving relative to the wellhead, even under the loads imposed by the down hole coiled tubing weight and the side pull of the coiled tubing reel. Further, the compressive loads from all downward forces had to be eliminated from the long lubricator to prevent buckling. The meant that the downward and overturning forces had to be carried through the tower, into a platform, then via platform supports, to the ground.
Solutions and Procedures to Assure the Flow in Deepwater Conditions
Authors: Gomes M.G.F.M. , Pemirs F.B. , Line A.C.F. 
Published: October 2008

Abstract
Petrobras has been developing deep water oil fields located in Campos Basin a vanguard subsea project which faces big challenges, one of them wax deposition in production flowlines. So, since 1990, Petrobras has been studying methods 10prevent and remove paraffin-way deposits. Tests of techniques based on chemical inhibition of crystal growth thermo-chemical cleaning (SGN), mechanical cleaning (pigging), electrical heating and thermal insulation were done and the main results obtained at CENPES (Petrobras R & D Center) started to be used in the field in 1993.
This paper presents solutions and procedures which has been used to minimize oil production losses at Campos Basin - Brazil.

Introduction
The occurence of different types of deposits on pipelines, which affect operational routine in offshore installations, leaded Petrobras to deal with this problem.
In order to evaluate the available methods for preventing and removing these deposits and develop others, the Program on Deepwater Exploitation Systems (PROCAP 2000) has been studying and testing many techniques. Special attention has ken driven to wax prevention and removal methods, for this. is one of the main operational problems faced up.
From the beginning of first phase of Albaccora field exploitation in 1989, it has been noticed that some production flow lines presents organic deposits build-up. This phenomenon happens when paraffin comes out of solution, as the oil reaches the WAP (Wax Appearance Point), due to low sea bottom temperatures.
Although Petrobras is aware about asphaltene, scale and hydrate occurrence, this paper will focus on wax deposition problems, and present difficulties, solutions, procedures adopted by Petrobras in minimizing wax deposit impact on deep water exploitation projects. The use of these techniques imply in additional investment that must be foreseen in the initial phase of the project.
The following aspects will be highlighted:How to predict the wax depositionHow to solve the problemProject implications on the development of oil field where wax deposit has been foreseen.The development of Albaccora, Marlim and Barracuda fields.

PROCAP 2000 - Flow Assurance in Deepwater Conditions Project
PROCAP-2000 is The Petrobras Program on Deepwater Exploitation Systems. The aim of this technological innovation program is the reduction in production costs, increasing productivity in deepwater fields and enabling oil production at water depths over 1000 meters. Production losses due to organic deposition in the flow lines of the wells located far from the production platform can be avoided through studies on the deposition phenomena and establishment of feasible operational techniques. The Flow Assurance in DeepwaterConditions is one of 12 projects included in the scope of PROCAP-2000. (see figure - I)
Measurement of Break Away Yield Stress of Waxy Crude Oil and Pipeline Restart System Design
Authors: Williams T.M. , Hsu J.J.C. , Patterson H.L. 
Published: October 2008

Abstract
Break Away Yield Stress (BAYS) has been measured on waxy crude oil from the South China Sea to help develop appropriate design specifications for the HZ production system. Design of subsea production systems for handling relatively high BA KS crude oils will be discussed. A BAYS measurement system for measuring the live and dead oils at various cooling rates and the effect of cooling rate on BAYS will also be discussed.
The measured BAYS of the HZ crude at seabed temperature indicated that reproduction was interrupted and the crude in the pipe line cooled to seabed temperature, the restart pressure would exceed the pressure rating of the originally planned pipeline. For way crude with high yield stress at seawater temperature, the production system must be designed to allow the production to be restarted after unplanned shutdowns.
BAYS of the oil can affect the economics of a crude production system. Accurate knowledge of the BAYS will al[o w optimum spacing of emergency clean out ports or other system modifications that may be considered for an optimum restart system design

Introduction
The crude oil produced in many fields has a pour point above the ambient temperatures that the crude oil may encounter. During normal production, the oil temperature may remain above the pour point. However during shutdowns, the oil may cool to below the pour point and gel. If the shutdown continues, the BAYS of the oil may continue to increase even after the oil gels. The pressure required to restart flow may exceed the pressure rating of the pump or the pipeline.
Accurate measurement of the BAYS of many waxy crude oils are needed so informed decisions can be made during system design and while developing procedures to be followed so production can be restarted planned and unplanned shut downs.
We have designed a system to measure the BAYS of stock tank and live crude oils at selected temperatures. The cooling rate of the oil can be controlled and measurement of the BAYS at the selected temperature can be delayed to best model field conditions.

Discussion
To measure the BAYS of an oil is fairly simple. Just cool an oil sample in a pipe to the desired temperature and measure the amount of pressure it takes to push the oil from the pipe. However, to obtain a measurement that is sufficiently accurate to be useful in planning a production system, several things must be considered. Some things to consider are:Cooling rate of the oil,Pipe material,Temperature, andLength of time atler cooling before measurement is made.
If the yield stress of live oil is to be determined, the measurement system must be designed to contain the live oil at a high enough temperature to melt all wax particles and to be filled without contaminating the oil. The system we have been constructed is discussed below.
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

Abstract
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

Abstract
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