bluuebunny/crossref_metadata_2025 huggingface dataset:
Viv Design of Large Diameter Export Riser Bottom Bend Spans
Authors: Lee Li , Valenzuela Ernesto , Keel Ryan
Published: June 2014

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

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

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

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'Souza Richard
Published: June 2014

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

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

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

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.
Development of X70 and Heavy Wall X65 Plates For Sour Service Pipeline Application
Authors: Bauer Juergen , Collura Carmelo , Schwinn Volker , Staudt Thorsten , Clipet David , Amoris Eric
Published: June 2014

Brazil due to its extraordinary oil and gas fields is one of the upcoming future markets for heavy plates for sour service applications. Such heavy plates are steels with high-class quality demands. Depending on the quality of the sources the HIC (Hydrogen Induced Cracking) resistance is a special requirement of these steels. By minimizing the HIC crack initiation sites as well as the crack propagation the HIC resistance is accessible. To achieve this, a careful design of all micro-structural features of the steel is necessary.

The utilization of the latest technology for steel and plate making is the central element of the production of such steels. Suitable metallurgical processes like clean steel treatment, casting in a technically sophisticated manner as well as special rolling techniques like the TMCP (Thermo-Mechanical Controlled Process) combined with suitable ACC (Accelerated Cooling) after final rolling provide the fundamentals of a homogeneous and resistance microstructure, especially with low level of imperfections, mainly non-metallic inclusions as well as reduced mid-thickness segregations.

The paper will point out the integrated overall production concept which provides the basis for the production of steel plates with consistent and reliable HIC resistance. The essential parameters will be explained, including the utilization of an appropriate quality assurance system.

The second part of the paper will focus on the gradual development to the strength level of grade API-5L X70 and higher wall thickness of grade API-5L X65. The feasibility of the production of such steels will be demonstrated by the presentation of recent deliveries, also interesting for the Brazilian market.

Introduction

The most line pipe projects with full sour service applications use the already established API-5L X65. But the still growing global demand on crude oil and natural gas and the involved shortage of the resources necessitate the exploitation of resources under more difficult conditions. Especially for the Brazilian oil and gas pipe market with its important resources in deep sea areas heavy wall API-5L X65 and/or API-5L X70 for full sour service are very meaningful for economically efficient as well as safe exploitation. From the point of costs it is also important to go to higher strength instead of enhancing wall thickness to manage high external pressure linked with deep sea areas. That is why all heavy plate producers in the world invest a lot of efforts in research and development of high strength line pipe grades for full sour applications [1–4].
Impact of Lubricating Materials on Arctic Subsea Production Systems
Authors: Akulichev Anton , Thorkildsen Brede
Published: June 2014

Lubricants represent a significant challenge encountered by any moving components in cold climate. They shall demonstrate good viscosity properties over a wide temperature span to be suitable for the service and sustain the temperature extremes in storage. Furthermore, heavy duty greases for subsea connectors exposed to well stream heating shall maintain the required level of lubricity for a prolonged period under water to be able to disconnect equipment at any time.

Raised HSE concerns in the Arctic drive the current equipment and technologies for offshore oil and gas exploration towards environmentally compatible solutions and zero discharge performance. FMC performed a pre-screening test of some environmentally friendly greases and pastes for riser connectors which clearly showed that most of those compounds were not able to meet all requirements. Typically " green" compounds had inferior characteristics and virtually could not pass even preliminary standard tests. Truly a compromise between lubricants properties and their biodegradability / toxicity level needs to be found.

This is a common industry challenge which needs proper attention from operators and major EPC contractors. As a short-term measure for existing fields being developed in near future it is proposed to make a JIP on rigorous testing and qualification of lubricants for Arctic. New promising " green" products recently introduced on the market should be included into the testing program.

Nevertheless, such approach most likely will not address all challenges and requirements in the harshest areas in the High North. One solution for those regions is advanced self-lubricating composite coatings. Recently the concept of coating incorporating capsules of liquid lubricant has been proven. A further development and testing in this field is certainly required, however at the end lubrication-free moving units and components may outperform conventional lubricated counterparts in terms of cold operation cycles, reliability, lifetime and environmental impact.
An Implementation of ISO 19906 Formulae for Global Sea Ice Loads within a Probabilistic Framework
Authors: Fuglem Mark , Richard Martin , King Tony
Published: June 2014

The ISO 19906 standard provides guidance for the calculation of characteristic ice loads on offshore structures in arctic and cold regions. Ice failure is a complex process and the development and improvement of ice load models can be challenging, in large part because of difficulties obtaining full-scale data and scaling issues when extrapolating small-scale test data. Many of the ice load models referenced in ISO 19906 were developed during arctic exploration in the 70's and 80's. Typically, simplified geometries are assumed for both the structure and ice features in order to obtain analytic solutions; other simplifications may be incorporated appropriate for the specific applications considered and information available. A significant proportion of referenced models provide the maximum load during an interaction, rather than the development of the load over time. This can be a limitation were penetration into a thick ridge is limited by available driving force and kinetic energy.

Given the large variety of ice conditions to which a structure may be subjected and the apparent randomness in ice fracture and damage mechanisms, there can be considerable variation in loads. Ice strength may be set to a characteristic fixed value, the ISO model for global sea ice loads is based on a relationship that considers ice thickness and contact width and is based on upper envelop fits to failure data. When determining the appropriate characteristic load on a structure, consideration should be given to exposure (i.e., the number and durations of ice interactions). Loads based on characteristic values for parameters such as ice thickness and ice strength could be inaccurate for scenarios where the exposure is significantly different than that on which the characteristic values were based. The application of probabilistic methods can be used to account for differences in exposure. While ISO 19906 references such methods, guidelines on implementation is limited.

This paper examines issues in implementing available formulae for ice loads on fixed structures within a probabilistic framework and shows how characteristic ice loads differ depending on the model and assumptions used. The Sea Ice Loads Software (SILS), a probabilistic framework developed by C-CORE for calculating characteristic ice loads using the methods referenced in ISO19906, is used for the analyses and comparisons.
Autonomous Surface Vehicles for Arctic Data Collection
Authors: Anderson Brian , Kleiner Art
Published: June 2014

The work on which this paper is based is field data and pilot testing results of variable payloads on Autonomous Surface Vehicles or Unmanned Surface Vehicles (ASVs/USVs), operating in variable industrial environments. Original field data from Multibeam echo sounder, Gyro, Motion Sensor, USBL Sonar, Passive Acoustic Monitoring for marine mammals, and ADCP data collection for ocean currents are all used to illustrate the ASV as a remote data collection platform for remote environments. By employing diesel electric propulsion and payload power strategies, the systems reviewed in this paper are capable of operation and station keeping in up to 6 knot currents, and do not require sun illumination for solar power, or favorable wind and/or sea conditions for propulsion.
A Disconnectable Dry Tree Semisubmersible Design Exposed to Iceberg and Harsh Environment
Authors: Mansour Alaa M. , Dib Michel , Zuccolo Ricardo , Bagaria Ashish , Greiner Bill , James Jolly , Kumar Dhiraj , Heidari Homayoun , Azevedo Jefferson
Published: June 2014

This paper presents an innovative design for a disconnectable dry tree semisubmersible floater for use in harsh environments and which could be exposed to the threat of iceberg impact. The use of dry tree Top Tensioned Risers (TTRs) in well completion has its advantage in allowing direct vertical access to production wells, which enables the use of dry-trees, drilling programs, and well work-over when required. Semisubmersible floaters offer significant execution and operational advantages over other types of floaters such as the quayside integration, and high flexibility on the payload and topsides area requirements. However, with the existing qualified tensioner technology, conventional semisubmersibles do not offer motion response suitable for dry tree applications. The free hanging solid ballast semi (FHSB Semi) is an enhanced semisubmersible design that maintains the advantages of the semisubmersibles while offering a very low motion response suitable for dry tree applications. The design and characteristics of the FHSB Semi is widely published elsewhere. In an area where floating platforms are exposed to icebergs and harsh environment, it is essential to design a system where the floater can be disconnected from the moorings and top-tensioned risers and be moved away from the iceberg's path. After the event the system should be designed to reconnect moorings and risers with minimal disruption to production and reasonable restriction on the reconnection environment. In this study, the FHSB Semi design has been further developed to enable disconnect/reconnect of the TTR and mooring systems. Detailed description of the disconnectable TTR and mooring systems is presented in this paper. A case study is also presented to illustrate the performance and the disconnection/reconnection of a FHSB Semi located offshore Newfoundland in a harsh environment area subject to icebergs.
Influence of Wave-Induced Iceberg Heave Motions on Risks to Subsea Equipment
Authors: Fuglem Mark , Ralph Freeman
Published: June 2014

In offshore regions where risk of iceberg contact with subsea equipment is unacceptably high, protection options include reduction of the probability of impact by placing the equipment below the seabed in an excavation, and use of protective structures to reduce the probability of damage given an impact. An initial estimate of the probability of impact from a freely drifting or scouring iceberg may be determined based on the chance that an iceberg with draft greater than the top of the subsea equipment drifts directly over it. A more detailed analysis might consider the increase in probability of impact as a result of iceberg heave and pitch motions.

In this paper, a methodology is presented for assessing the importance of heave motions of freely floating icebergs on probability of impact with subsea equipment protruding above the seabed. The method incorporates numerical and statistical modeling of random icebergs motions in irregular seas, including shallow water effects. Consideration is given to the mean clearance of the iceberg above the equipment, the random iceberg wave-induced heave motions, the geometries of the structure and iceberg and the time for the iceberg to pass over the site. Analyses are conducted on the effect of wave-induced heave motions of icebergs in wind-generated sea states and swell in water depths of 95 m and 60 m. A number of iceberg shapes are considered. It is found that for the conditions considered, heave motions do not have a significant influence on impact probability.

In evaluating the previous methods for estimating wave-induced iceberg motions, some deficiencies in previous iceberg heave and surge response amplitude operators were discovered, and improvements are recommended when estimating iceberg impact loads with gravity based structures and floating systems.
Feasibility of a Conical Piled Monopod in Multiyear Ice Environment Offshore Northern Alaska
Authors: Aurora Ravi P. , Williams Alan , Argiolas Ricardo
Published: June 2014

This paper presents the results of a study examining the feasibility of a Conical Piled Monopod (CPM) offshore Northern Alaska in about 41m water depth, fairly competent soil conditions, and Multi Year Ice environment. The study was conducted jointly by ConocoPhillips Company based in Houston, Texas and Granherne Ltd, a KBR Company based in Leatherhead, UK. ConocoPhillips sponsored the study.

Two CPM concepts were considered, the Standalone CPM covered in this paper and a Dual Rig Jack Up (Gemini) Assisted CPM. The latter is the subject of another paper to be published later.

The CPM was configured for two drilling rigs, assuming topsides weights ranging from 35,000 tonnes to 45,000 tonnes and corresponding operating weights from 60,000 tonnes to 70,000 tonnes respectively. Ice loads were calculated using ISO 19906 formulae where possible, otherwise using references within the ISO 19906 code and specialist ice load advice (Ken Croasdale) where necessary.

The CPM has been shown to be feasible in the Alaskan Sea for the two ice conditions considered, 6m thick level ice and a very rare 25m thick ice island event. The ice island event represents a very conservative scenario and further data may allow its severity to be reduced. In addition, there will be many months, if not years, after discovery before an ice island can potentially impact the CPM.

The CPM has a large enclosed volume available, which could accommodate a potentially significant amount of oil storage. However, this has not been quantified within this study work.

The CPM concept eliminates or greatly minimizes the need for seabed preparation, being a pile supported structure. It also does not require solid ballast for resistance against sliding due to ice loads; these two characteristics of the CPM can have a major positive impact on the cost and schedule of an offshore Arctic project.

ConocoPhillips has a Patent Pending on the CPM concept.
Effective Monitoring of Auroral Electrojet Disturbances to Enable Accurate Wellbore Placement in the Arctic
Authors: Poedjono Benny , Maus Stefan , Manoj Chandrasekharan
Published: June 2014

In measurement while drilling (MWD), wellbore azimuth is determined relative to the direction of the geomagnetic field. Converting this magnetic azimuth to a true azimuth requires accurate knowledge of the direction of the geomagnetic field at the point of measurement downhole. In the Arctic, MWD processing must include corrections for rapid changes in the geomagnetic field caused by auroral electrojet currents.?The auroral zone, those latitudes at which the aurora borealis (or the northern lights) occurs, is a region where the electric field of the magnetosphere precipitates along magnetic field lines into the ionosphere. At 100 km above the surface, this electric field drives auroral electrojet currents in the east/west direction, generating the strongest magnetic field disturbances on the planet. The direction of the geomagnetic field in the auroral zone can change by several degrees in less than an hour.

Data from geomagnetic observatory and variometer stations can be analyzed to characterize the auroral electrojets and compensate for the disturbance. Knowledge of the spatial structure of the electrojets' magnetic signature is essential for deploying a ground network of monitoring stations in the Arctic. This network provides the real-time geomagnetic infrastructure essential to support MWD operations, making it the most cost-effective technology available to achieve accurate wellbore placement in horizontal, relief well, and extended reach drilling, as well as in collision-avoidance applications.

In one case study using historical data from two nearby observatories from 1995 to the present, the disturbance field was characterized and a time series of maximum disturbances was derived and extrapolated to the year 2020. Maximum disturbance in the magnetic field was found to lag the maximum of solar activity by approximately two years, predicting the next maximum in 2015-2019.
NE Greenland Ice Study Group and Recent Project Work
Authors: Wright J. , Hammeken-Holm J. , Renganathan V. , Robertson S.
Published: June 2014

The region that lies off the northeast coastline of Greenland is of high interest to the oil industry. This is a very remote area, well known for the severity of its physical environment. Factors of note include a limited open water season, heavy pack ice conditions, icebergs, low temperatures and poor visibility. The constraints that are imposed by this environment will present significant challenges for various oil industry activities such as seismic data acquisition, exploratory drilling operations, and potential development and export systems. However, good data on the physical environmental conditions in this region are sparce.

In order to improve the current state of knowledge, a NE Greenland Ice Study Group was formed to conduct "directed ice R&D work" of relevance to oil industry needs. The concept for this group was based on a collaborative approach successfully used in Canada during the 1970's and 1980's. The NE Greenland group includes 12 oil companies that jointly discuss and identify key ice information requirements, together with the Bureau of Minerals and Petroleum (BMP), and support ice related R&D on a proportionate basis. The approach has proven to be a sensible and cost effective way to conduct work and make technical progress in a new region like the NE Greenland offshore, and has also been used by similar industry groups in the Disko West and Baffin Bay regions of Greenland.

This paper highlights the NE Greenland study group approach that has been developed, which is a good model to consider for other Arctic offshore areas, along with the NE Greenland ice studies conducted by our group to date. It also highlights some of the results of the NE Greenland ice study group projects carried out so far.
Arctic and Sub-Arctic Pipeline Routing Evaluations Enabled by Spatial AHP
Authors: White Charles N. , Paulin Mike , Palejwala Ashfaq , Burke Julie , Mower Kirk , McGee Simon
Published: June 2014

The Analytical Hierarchy Process (AHP) is employed to structure and prioritize the criteria (issues) that most strongly affect pipeline routing decisions for Arctic and sub-Arctic offshore projects. An AHP model is created incorporating these criteria and the pair-wise comparisons technique is used to establish weighting of the criteria. The collaborative pair-wise comparison approach allows all team members to explore and sound out each other's perspectives on the importance of each of the routing assessment criteria in a disciplined way that builds consensus around the model adopted for the cases under investigation.

This AHP model can then be tagged to a geomatics database automatically linking expertise in the pipelining disciplines with advanced geomatics capabilities for assessing export pipeline routing schemes to directly account for key considerations like flow assurance, geohazards, on bottom stability, bottom roughness, bathymetry, seabed morphology, sediment types, existing infrastructure, economics, public use regions, and environmentally sensitive areas. The paper describes how this linkage allows an automated scoring procedure that is then tested for robustness by sensitivity checks and demonstrates the methods via case studies.

When this method is applied to offshore Arctic pipelines, information can be incorporated that reflects the engineering, environmental, social, administrative, and infrastructure input that must be considered in routing/design. The model is then applied to challenging pipeline planning cases with sensitivities investigated in a way that confirms the robustness of the routing recommendations.

The paper clarifies how the issues and key technical information can be efficiently captured and applied within Arctic or sub-Arctic full field development planning studies that reflect real-world information (geomatics). The ability to easily accommodate changes in the engineering/technical basis and/or corporate priorities is highlighted, as well as the consensusbuilding strengths of this advanced methodology.
Ice-Seabed Gouging Database: Review and Analysis of Available Numerical Models
Authors: Babaei M.H. , Sudom D.
Published: June 2014

Ice gouging or scour may damage structures buried in seabeds, hence research on this subject is important. Numerical modelling is one of the most flexible and least costly methods of studying ice gouging. Previously, information on existing numerical models and their results was scattered in the literature. A new database has been created that tabulates this information. The database can be used to search numerical results and analyze knowledge gaps and correlations that might exist, in order to better understand and further advance knowledge of ice gouging phenomena. The database contains information on 206 runs from 18 major numerical studies. Using the database, knowledge gaps have been assessed. A list has been made of topics which were given little attention despite their probable importance, including deformable ice keel, different-from-seabed trench backfill soil, and simultaneous interaction of pore water and soil matrix in cohesionless seabeds. The available numerical model results show that pre-set gouge depth and the maximum depth of subgouge soil deformation are nearly linearly correlated. Maximum pipeline strain as a function of test set-up parameters is assessed. Profiles of subgouge soil deformation with depth from various sources are also combined and compared in this paper.
Ice-Soil-Pipeline Interaction during Seabed Gouging in Physical Tests: Database Analysis and Outstanding Issues
Authors: Barrette Paul D. , Sudom Denise
Published: June 2014

Ice gouging (or scouring) events affect the seafloor in a way that needs to be understood prior to determining safe and cost-effective burial depths of subsea pipelines in cold oceans. Knowledge on seabed scour phenomena has been gained by means of numerous physical tests in a laboratory or outdoors. Nearly 500 of these tests conducted over the past few decades were compiled into a database, a form of repository that is meant to be updateable, upgradeable and verifiable. This compilation shows that two distinct test set-ups were used: one in which a pre-set gouge depth was selected and vertical loads were monitored; the other with a pre-set vertical load and where keel heaving is allowed. Soil type and normal versus high simulated gravity are two other decisive parameters in test design. The results of this compilation are summarized. Parametric analysis of variables in the database is difficult due to significant differences in test programs. A comparison is made between seabed survey field data and the ranges of gouge width and depth obtained (or targeted) in the tests. A number of significant issues and information gaps have been identified, which could be given priority in future test programs.
ARKTOS Shear Zone Evacuation Craft Self-Righting Model Tests
Authors: Hall T.A. , Seligman B.H.J.W. , Kharrazi M.
Published: June 2014

The ARKTOS Evacuation Craft has been the primary means of emergency evacuation on Arctic and Caspian Sea bottom founded oil exploration and production facilities for over 20 years.

Oil production strategies are currently being developed by major oil companies for operations within and beyond the Arctic Shear Zones, where the mobile polar pack ice and the static land-fast ice meet.

A major area of concern for any development within and beyond the Shear Zones is Escape, Evacuation, and Rescue (EER) capability, due to the extreme ice and sea conditions that will be encountered. In response to a major oil company initiative, a conceptual design for a 75 person self-righting ARKTOS Amphibious Evacuation Craft suitable for operation in this region has been developed.

As part of the ongoing design process, an extensive series of self-righting model tests have been carried out to confirm the Shear Zone Craft will be capable of self-righting in all combinations of pitch and yaw, both fixed and free, which the dual unit craft is capable of attaining.

Four load cases covering the range from maximum displacement to maximum vertical center of gravity (VCG) were evaluated with 36 combinations of pitch and yaw for each load case, resulting in 144 individual tests.

This paper describes the model test procedures and results of the model test program. It also includes recommended minor design enhancements to ensure the Shear Zone Craft will be self-righting in all load cases.