bluuebunny/crossref_metadata_2025_split huggingface dataset:
Viv Design of Large Diameter Export Riser Bottom Bend Spans
Authors: Lee Li , Valenzuela Ernesto , Keel Ryan 
Published: June 2014

Abstract
This study presents a review and new approach to VIV design of large diameter pipes hanging off from a collar and restrained laterally by guides. The specific application is for a subsea tie-back, which are common in deepwater field developments. The exported fluids are transported by a pipeline from a deepwater Floating Production Installation (FPI) to a valve assembly on the seabed, and then through a tie-back bottom spool to a fixed platform in shallow water. The incoming riser is attached to the structure of the receiving platform via clamps that allow no restriction in motion along the axial direction of the riser. VIV is often one of the controlling parameter that governs the design of the bottom spool and the riser.
Vortex-shedding design of subsea pipeline spans, and subsea spool tie-backs have been studied by other authors. This is a review study of the subject matter, but the main difference is that it considers the spool, bottom bend span and the upper riser as one single structure; thus the vibration and soil stiffness interaction of the bottom spool is accounted for in the VIV response of the upper riser spans; and viceversa, the vibration response of the riser is accounted for in the bottom spool.
Future bypass and pre-commissioning capabilities for large diameter subsea tie-back spools of incoming import risers that connect to a dual subsea isolation valve assembly; as well as pulltubes of deepwater Spars will benefit from the findings of using this approach. Both cases consist of large diameter pipes hanging-off from a collar restrained laterally by guides.
The main conclusion of this study is that VIV and specifically in-line VIV cannot be ignored because usually becomes one the governing design parameters for this type of applications.

Methodology
The riser and bottom spool are modeled as a continuous multi-span beam using Flexcom3D and Orcaflex. The riser pipe may exhibit VIV motions for both: in-line and cross-flow current directions. The programs Shear7 and RISVIC are used to simulate VIV in the frequency and 3D time domain respectively. A numerical example of a large diameter 20-in export riser is presented to demonstrate some of the challenging design issues in 750 ft. of water in the GOM environment. The fatigue damage resulting from both in-line and cross-flow VIV is estimated from the frequency and time domain responses. Among the key design issues are the required clamp distance, radial gap, appropriate boundary conditions at the clamp locations and their effect on the resulting modes and fatigue damage.
The riser clamp spacing is usually designed so that no cross-flow VIV occurs and in-line VIV is mitigated: This means that if it is not possible to eliminate in-line VIV by design, then a fatigue analysis shall be performed to demonstrate whether the riser presents an acceptable fatigue life.
Produced Water Deoiling System Qualification Program
Authors: van Wingaarden Hubert , Lammers Bart , Tienhaara Mika 
Published: June 2014

Abstract
Efficient and robust produced water treatment technology is necessary for many oilfield explorations because of increasingly strict discharge regulations, but also for applications to debottleneck mature fields, as well as for subsea applications with produced water re-injection.
The performance of produced water treatment systems can be improved by using mixedflow hydrocyclone technology. In this novel design an even flow inlet distribution is created which can be used to reduce the pressure drop as well as to enable an increased throughput. The mixed flow technology offers high separation performance and reliability for a wide range of operating conditions, including highly demanding produced water streams containing heavy crude.
A testing campaign of the mixedflow hydrocyclone was performed on a dedicated test loop located at the Federal University of Itajuba in Brazil. Goal is to determine the performance (i.e. separation efficiency) for a wide operating range, including varying crude types, flow rates, inlet oil-in-water concentrations and reject rates. Based on this work, a performance prediction tool and capacity curves have been established which allow for robust design of produced water treatment facilities.

Introduction
The upstream oil industry spends a considerable amount of capital and operation effort providing and maintaining produced water treating systems. More and more the produced water treatment systems influence the overall economics of offshore oil field exploration as in many cases the produced water rate increases continuously.
Challenging design cases are especially found when dealing with low API crudes (i.e. heavy oil) where the driving force behind cyclonic separation is significantly lower than for light crudes. Furthermore, ongoing strengthening of environmental specifications on produced water discharge, has a challenging impact on the design, as the allowable Oil-in-Water (OiW) content before discharge, measured as parts-per-million (ppm), is reduced further and further. Therefore, treatment of produced water with hydrocyclones is of high importance to enable produced water discharge and even more important for reinjection purpose into the wells.
The understanding of the dependency of hydrocyclone performance (efficiency) on droplet size distributions, crude density, reject flow rates and inlet OiW concentrations is fundamental to allow for proper design of produced water treatment facilities. Furthermore, this understanding is essential in order to have performance prediction tools established for the purpose of the process design of these facilities. Moreover, more developments are now considering subsea separation, whereby produced water can be separated and re-injected into the wells and thus avoiding produced water to be transported in the flowlines and risers to the surface facilities for treatment. For such subsea applications, there is a need for robust high performance technology with proper qualification work done.
Development of an Ultrasonic Corrosion Probe
Authors: Camerini Claudio Soligo , Patusco Carlos Alexandre Pereira , Adamowski J.C. Arroyo , Buiochi F. Arroyo , Almeida Neusvaldo , Tsuzuki Marcos 
Published: June 2014

Abstract
Corrosion monitoring is one of the most efficacious mechanisms that allow controlling the integrity of pipelines and its application is required by international standards in several situations. The ordinary technologies used in corrosion probes, like mass coupons, have some limitations regarding costs and QHSE issues; it leads to the development of alternative technologies. In the case of subsea pipelines, the use of the traditional coupons is limited to the " topside" section of the pipeline, usually in its beginning and end. It restrains strongly the process of integrity assurance in subsea pipelines. This paper describes the development of an ultrasound system of high sensibility to overcome these limitations. It is called "PROVUS" and it is able to estimate corrosion rates very accurately. This system presents many advantages when compared to the traditional coupons, such as: they are non-intrusive, easy to handle/deploy, safer and more flexible. This paper details the present stage of development of the ultrasonic corrosion probe, detailing: the validation process by means of over 6000 hours of "blind tests", i.e., tests in which the applied corrosion rate was only informed after its detection by the ultrasonic system; the applications for onshore and subsea pipelines; the mechanical design and the adjusts in course to turn the tool suitable for ROV (Remotely Operated Vehicle) operation.

1. Introduction
Corrosion monitoring is a very important mechanism to allow the evaluation of pipelines integrity.. Many standards require or recommend the use of corrosion probes as corrosion monitoring items. The use of the traditional coupons is not feasible for subsea pipelines except in the topside sections, i.e., normally in the pipeline's beginning and end.
Papa-Terra Project: Use of Innovative Solutions for Heavy Oil in Deepwater
Authors: Condessa Diego Santos , Goncalves Willer Planas , Vieira Saon Crispim , Danno Giancarlo de Souza 
Published: June 2014

Abstract
Papa-Terra field is operated by Petrobras in Partnership with Chevron, and located in the Campos Basin, Brazil, 110 kilometers from the coast.
Discovered on June 2003, it could be identified an oil interval of 14.6°API in Turbidities Sandstones. The field extends over an area of 183 square kilometers, in water depth that varies from 400 to 1400 meters.
Due to the high viscosity oil and low API grade, creative and innovative solutions with technological advances were incorporated to the project.
The development of the field considers an integrated production system consisting of an FPSO interconnected to a TLWP, with dry completion wells. By this way the production of ultra-heavy oil in deep water becomes viable, opening a new frontier for the production of high viscosity oil at reservoir and enabling rapid intervention in the wells for the ESP (Electric Submersible Pumps) maintenance.
There are 13 dry completion horizontal production wells interconnected to the TLWP, added to 5 productions and 10 water satellites injection wells connected to the FPSO. The wells drilling from the TLWP will be supported by a TAD rig (Tender Assisted Drilling). This allows the drilling rig to be temporarily installed upon the TLWP, which enabled significant optimization of the project by the size and cost of TLWP reduction.
The wet completion production wells will be interconnected to the FPSO using flexible pipeline with electrical heating and temperature monitoring system, to mitigate the production losses risk during production restart.
The Subsea injection wells will be equipped with Christmas Trees in Piggyback. To maximize the recovery, with the maintenance of high water injection flow rate, it is considered a pilot system of polymers injection in one of the water injection wells in order to elevate the water viscosity.
The production from the TWLP will be transferred by multiphase flow pumps to the FPSO through Fluid Transfer Lines (FTL) in a mid-water depth configuration. It will be the first use of this kind of solution in Brazilian waters and this configuration will avoid the cooling of the oil as it can occurs on conventional solutions when the lines are installed on the sea floor at deep water.
The Tension Leg Platform Technology - Historical and Recent Developments
Authors: Aggarwal Rajiv , D&apos;Souza Richard 
Published: June 2014

Abstract
The first Tension Leg Platform (TLP) was installed in 1984 to develop the Hutton field in the Central North Sea in about 500 ft of water. It successfully demonstrated the ability of a floating platform tethered to the seabed to drill and produce with surface trees. In the ensuing years, twenty three additional TLPs have been installed and five more sanctioned, in most major deepwater producing regions around the world, in water depths down to 5,200 ft.
The TLP today is a mature and proven deepwater production platform and is routinely included as a platform concept building block for many deepwater prospects during field development planning for dry or wet tree scenarios. This paper will present a retrospective of TLP development that includes:An overview and description of TLP hull configurationsBasic hull and tendon design considerationsA chronology of TLP designs, applications and contracting strategiesThe evolution of top tension riser (TTR) designsThe evolution of TLP tendon and foundation systemsImportant updates in codes and standards used for TLP design and construction
This paper highlights the progression of TLP technology and contracting strategies of the installed and sanctioned TLPs. The paper provides a snapshot in time to capture the evolution and current state of TLP technology. The impact on TLP design in Gulf of Mexico (GoM) from the new API RP 2T is demonstrated via an example of a pre and post Katrina sanctioned TLP.

TLP System and Hull Configuration Overview
The TLP is one of several mature floating production platforms in the Offshore Industry's arsenal to enable development of deepwater fields in any openwater offshore producing region in the world. It was conceived in the 1970s as a means of enabling direct vertical access to wells in water depths beyond the commercial reach of fixed and compliant platform capabilities. Fundamentally, it consists of a buoyant hull, which supports the topsides and well systems, anchored by rigid tendons to a seabed foundation to restrain vertical motions in waves. Excess buoyancy pretension the tendons that limit the horizontal offset to a prescribed watch circle. The heave restraint enables production wells to be tied back to the TLP deck by tensioned vertical risers to " dry" trees. The dry tree facilitates easy downhole access for well intervention and reservoir management to maximize hydrocarbon recovery from a reservoir. This is particularly applicable for highly compartmentalized and stacked reservoirs. It also simplifies running and retrieval of downhole electric submersible pumps (ESP's) to further boost well production rates and ultimate recovery. Major TLP components are illustrated in Fig. 1.
Roncador Module IV: A Successful Case of Heavy Oil Projects in Ultradeepwaters
Authors: Moro Henrique Peres , Maia Gustavo da Cunha , Lage Daniel Henriques Mesquita , Bordieri Eduardo 
Published: June 2014

Abstract
The Giant field of Roncador was by far the largest discovery made in Brazil in the 90's. Its approved Development Plan relies on its separation in four modules, due to significant reserves involved and difference among oil characteristics found. The field is already producing with SS P-52 and FPSO P-54 since 2007, for modules IA and II respectively. Soon the field will also count with SS P-55, which will start operations for Module III in 2013 and FPSO P-62, which will have its first oil for Module IV at the first quarter of 2014, and represents the focus of this work.
The Roncador Module IV is located at the center of the block, placed on the northeast of Campos Basin, 125 KM far away from the Brazilian coast. Currently, its reserves are over 500 MM boe, saturated with 18 ° API heavy oil. The wells are being constructed in ultra deep waters, with variations depths between 1650 and 1750 meters of water column.
This paper presents an overview of the project, including strategic drivers adopted on its design, which sought to mitigate risks and reduce deployment costs, as well as its scope and the journey since the selection of alternatives through the current status, with the FPSO P-62 under final phase of construction and assembling at the Estaleiro Atlântico Sul Shipyard in Recife and near the beginning of its operation in the Roncador field. The operation in advance of four wells (three producers and an injector one) using the already installed infrastructure of the field, will also be presented in this work.

Introduction
Roncador giant field, with an area of ??109 km2 and discovered through the exploratory well 1-RJS-436A in October/1996, is located in the northern area of Campos Basin, northeast of Albacora and Albacora Leste fields, lying about 125 km from São Tomé Cape, in the north coast of Rio de Janeiro State.
The field is associated with a major fault system with major dimensions and dominantly extensional profile. Due to the large areal extent, the large volume of oil in place, different types of oil and limited processing capability in deep water the development of the field was divided into 4 modules (Fig 1) as follows:–Module 1A, saturated with oil of 28 ° API, which was divided into two phases: Phase 1, which began production in December 2002, and Phase 2, which began production in November 2007.–Module 2, saturated with oil of 18 ° API, which started production in December 2007.–Module 3, saturated with oil of 22 ° API, which production start forecast is end 2013.–Module 4, saturated with oil of 18 ° API, which will be the focus of this work, still in progress. As a development strategy, the production of the module started in December 2012 due to an Early Oil Production Program, with a subsea tie back to existing facilities nearby module 4. However, the main objective is to develop the field through the FPSO P-62, which is expected to start the early 2014.
Comissioning and Startup of Subsea Marlim Oil and Water Separation System
Authors: de Oliveira Dennis Azevedo , Pereira Rogerio da Silva , Capela Moraes Carlos Alberto , Baracho Vitor Pastor , de Souza Ricardo dos Santos Alves , Euphemio Mauro Luiz Lopes , da Silva Fabricio Soares , Monteiro Andre Sampaio , Casanova Christiano Correa , Duarte Daniel Greco , Raposo Gelmirez Martins 
Published: June 2014

Abstract
The objective of this paper is to describe the adopted procedures and operations that were used to process commissioning and start-up the Marlim Subsea Oil and Water Separation and Water Re-injection System. This system is much more complex than the conventional subsea manifolds and, similarly to the previous phases of this project, the commissioning and start-up phases also faced many challenges that had to be overcome. Several subsea equipment are part of the system; among them we should mention an unconventional "harp" gas-liquid separator, an oil-water "pipeseparator", cyclonic desanders (both for multiphase inlet stream and for produced water stream), two stages of hydrocyclones to remove oil from produced water and a water injection pump.
Besides these equipments, instruments and multi-functional control modules are also part of the system. The problems faced during commissioning and start-up activities and the adopted solutions to solve them are also discussed. This paper will cover the start-up activities describing the following sequence:re-start-up of the production well through the subsea system by-pass line to topside,alignment of well multiphase production stream through the subsea separation system to check separation performance and suitability of produced water quality for re-injection andfinally start up of re-injection of produced water into the injection well.
The requirements for logistic support that are very much different from the ones required for topside installations are also discussed. New " paradigms" of operating facilities imposed by subsea environment constraints, are also suggested and discussed.

Introduction
The Marlim Subsea Oil and Water Separation and Water Re-injection System (SSAO) is an innovative pilot project installed as a Pilot System for the well MRL-141, connected to the host production unit (FPSO), P-37, in Marlim Field, Campos Basin. The objectives of the project are: platform debottlenecking of the water treating facilities; increasing production by reduction of back pressure on the wellhead. Besides these objectives, another important aim of the project is to prove the concept and qualify the adopted technologies for future other applications. As a pilot project, the SSAO was designed to work for a minimum of 5 years, without retrieving of any components, removing, treating and re-injecting free water from the production of MRL-141, as shown in Table 1.
A Coiled Tubing Perforating Solution Incorporating a Gun Deployment System and Dynamic Underbalance Technique Improves Well Production in High Angle Deep Gas Wells in Saudi Arabia
Authors: Leal Jauregui Jairo Alonso , Al Jubran Hasan Hussain , Al Buhassan Shaker Abduallah , Bolarinwa Simeon 
Published: June 2014

Abstract
Saudi Aramco has recently initiated a change in gas well design in the Ghawar field of Saudi Arabia. The new approach is to drill deviated cased hole gas wells through the reservoir to increase the length of contact of the productive zone and thereby increase production potential. Typical gas wells were drilled as a vertical cased hole through the reservoir or open hole horizontal gas wells.
The increased well deviations, measured depths and resultant increase in reservoir sections required a new approach to the perforating solution for these wells to connect them to the gas plants. Various techniques were reviewed, considering safety, operating efficiency and well performance. The final solution was to deploy the perforating systems on electric coiled tubing (CT) and run all the guns in one run using completion insertion and retrieval under pressure (CIRP) as a deployment system, which allowed the guns to be run and pulled under live well conditions without having to kill the well.
This paper details the learning curve and lessons learned of the implementation of this technique in five gas wells. The deployment system and pressure control equipment were optimized to satisfy Saudi Aramco's requirement for three barriers. A CT cleanout run was added before perforation to remove any debris from the wellbore causing a problem to the depth correlation tools. An existing CT tower was used to support the very long wellhead stack, but due to its height limitation a special solution was implemented to enable safe CT operations. A deployment system under live well conditions was used to minimize CT runs, operating time and cost savings. The static underbalance condition was set before running the guns, combined with the dynamic underbalance perforating technique and deep penetrating charge gun design were implemented to optimize the well performance. This technique allowed safe and efficient perforating in a single underbalance run of these five gas wells.
The paper also covers the planning of the perforating solution, Health, Safety and Environment (HSE) considerations, equipment selection, operational procedures, job execution and results.