bluuebunny/crossref_metadata_2025 huggingface dataset:
Novel Single-Trip Upper Completion System Saves Rig Time in Deepwater Offshore Brazil
Authors: Vilela Alvaro Jose , Carvalho Frederico
Published: July 2009

This paper outlines the mechanism and functioning of One Trip Upper Completion System using an hydraulic tubing compesating device (HTCD), the UST (Upper-Completion Single-trip System) that enables the integration of all equipments of an upper production string in order to run in hole in one single trip.

The UST with HTCD is an upper completion system that integrates safe production string running in hole and simplified hydraulic release after connecting the lower completion equipment to the upper completion system.

This paper also emphasizes the difference amongst few systems from conventional dual trip upper completion until other types of tubing seals receptacles used for single trip upper completion, stating all mechanical differences and their peculiarities. This document describes field experiences of Upper-Completion Single-trip (UST) installations using Single Trip Hydraulic Tubing Compensating Device (HTCD) system and establishes a comparative analysis of rig time savings and operation differences using conventional methods compared to the UST with HTCD.

Introduction

In 2004 first single trip production string was installed. This first successful experience was achieved using a mechanical single trip mechanism and the main objective of this method is to reduce rig time during upper completion installation procedure. The average rig time saving since first deployment of a upper completion single trip has been 24 hours. (1)

The reasons upper completion single trip technique has increased in Campos Basin are as follow:Horizontal deep water completions;Use of large bore Completions;Pressure and Temperature Gauges in the production string;Increased number of well control parameters therefore the necessity of larger number of control lines;Chemical injection mandrels and injection lines;Electric Cable and protection clamps;

Upper completion string lay out has become complex and therefore deployment limitations has been the challenge. Features as horizontal lower completions; prohybitive rotation of upper completion string and the minimum tolerance between casing ID and some equipments of the production string as clamps and tubing hanger are the main application for upper completion single trip methods as the technique minimizes production string deployment and maximize rig time saving. (See Figure 1)

First hydraulic actuated upper completion single trip was run in Campos Basin in Brazil in August 2005 using HTCD. Since 2005 more than 25 hydraulic actuated upper completion single trip has been run in Brazil succesfully.
Practical Application of Probabilistic Fracture Mechanics for Structural Integrity Management
Authors: Dinovitzer Aaron S. , Semiga Vlad , Tiku Sanjay , Bonneau Carole , Wang Ge , Chen Nianzhong
Published: July 2009

This paper describes an approach to the estimation of time dependent structural reliability of crack like features based upon codified fracture mechanics (e.g. BS7910, API579) techniques. A numerical simulation methodology is used to consider statistically defined through life wave load effects generated using recognized hydrodynamics codes and statistically defined defect, structural geometry and material property data, in estimating probabilities of structural failure. The approach outlined in this paper may be used to support through life integrity management of pipe, platform and ship structures subjected to uncertain variable amplitude loading.

An FSO double bottom hull structure cracking scenario is used in this application of fracture mechanics in the prediction of the probability of achieving a given fatigue life considering the crack growth and final failure using an automated analytic tool. The streamlined analysis tool will be described along with its inherent assumptions and approximations in demonstrating the sensitivity of the structural reliability estimates to the problem data and assumptions. The process employed and results presented are considered unique in terms of their ability to describe the time dependent nature of fatigue reliability considering a range of defect types and structural geometries.

The paper provide guidance and demonstrate through a practical application, the utility of fracture mechanics in considering structural reliability in developing critical flaw sizes to support inspection and repair criteria. The same techniques will also be used to define inspection intervals while considering the influence and significance of uncertainties in load and material properties. In presenting this sample application, the intended future application and further development of this technology is presented for discussion.
SS "Floating Offshore LNG" - Operational Experience With Ship To Ship (STS) Transfer Of LNG
Authors: Englebert Patrick
Published: July 2009

The paper describes the design, installation and operation of a Ship to Ship (STS) transfer system for LNG. It addresses the qualification of the cryogenic hoses and the emergency-disconnect couplings as well as the operational procedures for the berthing and transfer operation offshore.

The system uses ‘standard’ components, adapted only where needed for its new function. The operational procedures for berthing offshore have a long and proven track record in the oil lightering industry. The net result is a simple and cost effective solution for offshore transfer of LNG, developed in a fast and efficient manner and already proven with more than 10 commercial operations.
Tahiti Flowline Expansion Control System
Authors: Thompson Hugh Miller , Reiners Jim , Brunner Mark S. , DeLack Kristen , Qui Xinhai , Noel Clyde
Published: July 2009

The search for offshore petroleum reserves has taken the energy industry into deeper waters and deeper wells. A byproduct of deep-water discoveries is often a high-pressure, high-temperature (HPHT) reservoir. Reservoir fluids are often transported to a floating production facility (FPF) via carbon steel flowlines and risers. Pressurization and heating of flowlines that were installed empty and cold can lead to significant longitudinal expansion.

If left uncontrolled, significant expansion can often lead to excessive stresses and strains in flowlines or other system components. In some cases, uncontrolled expansion can lead to local buckling of the pipe cross-section or high stress-range (low-cycle) fatigue failure, resulting in a leak to the environment.

The Tahiti Project in the Gulf of Mexico presented a number of different flowline expansion system problems, including high pressure, high temperature, future water injection and reservoir souring, global lateral buckling and fatigue associated with a number of operating cycles, high flowline end expansions, high riser bottom tensions, and flowline walking (soil ratcheting).

Additionally, the stringent design challenges of the project produced corresponding challenges in the area of welding.

This paper discusses some of the flowline expansion control techniques used on the Chevron Tahiti Project in the Gulf of Mexico. Midline expansion control via distributed buoyancy and end expansion control via a novel stab and hinge-over (patent pending) Pipeline End Termination (PLET) located on top of a suction pile are discussed, along with other expansion control topics. The welding requirements, the challenge of setting up an onshore multi-joint facility, welding strategies, and the corresponding results will also be discussed.

Project Overview

Tahiti is a joint venture development between Chevron, StatoilHydro and TOTAL E&P USA with Chevron as the designated operator. The nominal production capacity of the facilities is 125,000 BOPD with associated gas and water. The Tahiti field layout for the initial phase is shown in Figure 1. The field consists of two production drill centers, located in Green Canyon Block 596 and 640 respectively, in approximately 4,100 ft water depth. The production manifold from both drill centers is tied back to a single Floating Production Facility (FPF) in Block 641, through wet insulated flowlines and steel catenary risers (SCR). Not shown in Figure 1 are two future water injection drill centers, which will be tied back to the FPF with flexible pipe flowlines and risers.
SS-FA - Flow Assurance Challenges in the Papa-Terra Project
Authors: Santos Junior Jesulino , Paternost Guilherme , Condessa Diego
Published: July 2009

The Papa-Terra project is among the most complex subsea developments executed in Brazil. Flow assurance strategies were a key driver because of the extreme water depth, the high viscosity and low API (<15 API) of the produced fluids. Petrobras has been considering the first TLWP, which will be installed 350 m away from a FPSO, with multiphase flow between units.

This project demanded a new approach on fluid behavior model and the adoption of some technologies not applied in the Campos Basin yet due mainly to emulsion impact in fluid viscosity. For example of these technologies are a dry completion unit with high power ESP's installed in deep water (4000 ft) and electrical heated flexible pipes. As another example the studies resulted in a new fluid model to be used in flow simulator that considers viscosity data measured in laboratory.

This paper gives an overview of the main flow assurance challenges faced on the basic project development, that include heavy oil modeling applied to an offshore deepwater field, multiphase flow transport between two production units (DCU and FPU) and dry completion unit using high power ESP as lift method.

Introduction

The Papa-Terra field is located offshore on south of Campos Basin, approximately 110 km from the coast of Cabo Frio, at Rio de Janeiro State, under 400 to 1400 meters of water depth (Figure 01). The field is at the Exploratory Block BC-20, 100 km south west from Petrobras Pampo's platform. It's a joint venture between Petrobras - responsible for the operation- and Chevron.
Subsurface Safety Valve Control System for Ultradeepwater Applications
Authors: Bane Darren , Peoples Brock
Published: July 2009

The typical subsurface safety valve for deepwater high-pressure/high-temperature (HP/HT) subsea applications employs many operational techniques including pressure-balanced pistons using gas energy for assisted closure, hydraulic balance lines, or a heavy spring to ensure failsafe closure in the event of an emergency shutdown. Each of these techniques has an impact on the valve's characteristics, which can raise concerns about valve operation or reliability.

A solution is desired that minimizes valve opening pressures by balancing tubing pressure, yet allowing extreme valve setting depth capability without compromising operational characteristics such as high opening pressures or pressure-balanced pistons using long term valve gas charge storage.

This paper discusses a new surface-controlled subsurface safety valve (SCSSV) control system that uses the low opening pressures of a tubing-pressure-insensitive safety valve, without gas-charged assisted closure or dual control lines for balanced line applications. This system eliminates the need for pressure reversals across the valve's critical actuating piston seals, which increases valve reliability and sealing performance while maintaining tubing pressure insensitivity. This control system allows for deeper valve depth capabilities compared to the methods previously discussed, allowing the safety valve to overcome annulus pressure buildup scenarios not possible in current SCSSVs for the applications described.

This paper presents design considerations using an SCSSV control system allowing technological accomplishments not previously possible with existing SCSSV technology. Test results demonstrate the suitability of the new control system design for previously unattainable valve operating depths in aggressive well designs or annulus pressure buildup situations while enhancing valve reliability.

Introduction

Deepwater production and operations in the outer continental shelf (OCS) is defined by the United States Minerals and Management Service (MMS) as operations taking place in OCS water depths in excess of 1,000 feet or 305 meters1. Given that deepwater discoveries are considered higher-risk ventures with unique operational, environmental, health, and safety concerns, it is no surprise that the visibility and criticality of subsurface safety valve designs for these applications are taking center stage in critical field completions.

Many projects in the Gulf of Mexico are taking place in excess of 7,000 feet of water depth and new discoveries support the future of deepwater development as technically feasible and financially justifiable. Existing technologies for subsurface safety valves each pose unfavorable features or risk when exceeding the earlier noted depths. Recognizing the high costs associated for a deepwater well workover, every precaution must be taken to ensure optimum valve performance and reliability.
Henning Devices: A New Class of VIV Suppression Apparatus for Offshore Tubulars
Authors: Allen Donald Wayne , Lee Li , Henning Dean L.
Published: July 2009

This paper introduces a new class of vortex-induced vibration (VIV) suppression apparatus, Henning devices. Test results for a number of such devices are presented and discussed. One of the main advantages of these novel devices over helical strakes and streamlined fairings is that the coverage density required to be effective is reduced from about 70 to 80% or more to approximately 20 to 25%. The drag on the tubulars with the light coverage density is therefore significantly reduced, compared to that of helical strakes. An additional advantage of Henning devices over fairings is that they are not required to rotate to be effective at reducing VIV, as evidenced by the tests. With the application of this new type of hardware, great cost savings can be expected.

Introduction

Offshore tubulars used in oil and gas exploration and production are often protected from vortex-induced vibration (VIV) with add-on hardware. Among the various types of suppression devices, helical strakes and streamlined fairings are the most common. These apparatus are effective at reducing VIV, though each has its own advantages and disadvantages [1,2]. One common feature to strakes and fairings is that a coverage density of greater than 70 to 80% is normally required to effectively mitigate VIV [3]. For example, if a suppression coverage length of 1,000 ft of the tubular is determined necessary, the required amount of suppression, in linear feet, should be at least 700 to 800 ft spaced evenly along the 1000 ft length.

Extensive VIV testing has been performed at Shell Westhollow Technology Center current tank, to explore more efficient suppression devices. As a result, a new class of VIV suppression hardware was discovered in 2006. In early 2007, a general methodology for VIV suppression was developed based upon the understanding of the test results. Additional tests, at higher Reynolds number, were subsequently conducted to further validate these novel concepts.

This paper presents and discusses some of the test results for this new class of suppression devices. First, the test facility and setup are described, followed by an introduction of various types of Henning devices. Test results for three examples (tribladed, square, and fixed 4-bladed devices in a range of applications) are presented next to illustrate various features. Conclusions are drawn thereafter.

The information presented in this paper should be of interest to offshore engineers and project managers involved in platform, mooring and riser design as well as project execution, as it discusses some of the latest developments in VIV suppression.
SS - Ocean Mining "Extending Deepwater Technology to Seafloor Mining"
Authors: Yu Chenten Alan , Espinasse Philippe
Published: July 2009

This paper builds on the experience of designing, and building production and drilling risers for oil and gas fields and extends into deepwater mining. With the recent discovery of high grade seafloor massive sulphides (SMS) in Papua New Guinea, New Zealand and elsewhere, there is a resurgence of interest in deep ocean mining. This renewal of interest has been spearheaded by Nautilus Minerals through its Solwara 1 project; in 1,700 m of water, with a production rate of 2.0 million tons per annum. Neptune Minerals Plc also endeavors to produce SMS with a similar production rate. This paper describes the two different deepsea SMS lifting concepts being developed by the two projects and the design challenges encountered during the course of the project executions for the two mining companies.

Nautilus plans to explore other adjacent fields with water depths reaching and surpassing 2500 m. It will use a riser and a lift system that utilizes a steel vertical riser combined with a bottom-suspended displacement pump for lifting the mined ore slurry. Waste water is separated from the slurry and then discharged at the seafloor. Many technical challenges have to be overcome to achieve the required performance, especially in the areas of lifting solids in a two-phase flow. Among these challenges are erosion and corrosion issues, two-phase flow assurance technology, methods of defining the system operational windows, and the overall integration of the equipment packages for the brand new industry.

Separately from Nautilus, Neptune Minerals Plc commissioned an engineering scoping study for technologies for the commercial development of SMS deposits offshore New Zealand. The scope of the conceptual study was to screen options regarding subsea mining tools and strategy, alternative SMS lifting methods, and SMS processing.

The SMS mining options integrated existing marine equipment and technologies, and the recommended lifting system incorporates a flexible production riser with an airlift system connected at the seafloor to an ore crusher and seafloor miner.

The objective of this paper is to describe the two deepsea SMS lifting concepts and approaches to help pave the way for the future development of systems of other potential miners. Both authors have been involved extensively in the development of deep ocean production and drilling systems for the last two to three decades. Various parts of their experiences were used for the overall deepsea mining system configuration and for the evaluation of the airlift and displacement pumps for lifting SMS from the seabed to the surface. The results depicted here draw heavily upon those experiences.
SS Ocean Mining: Development of Environmental Research related to future Deep Sea Mining - Are Concerns justified and what should be done?
Authors: Schriever G.
Published: July 2009

During the past fifty years, the deep sea has moved more and more into the realm of societal interest. Waste dumping into and ore mining in the deep-sea were discussed and the international community agrees that environmental considerations and further research on potential impacts on the largest environment of our earth (about 60%) are obligatory before such industrial intrusions start. Even during the initial exploration phase on polymetallic nodules at the beginning of the 1970s, environmental studies were being conducted: Deep Ocean Mining Environmental Study (DOMES) and Metalliferous Sediments Atlantis II Deep (MESEDA) both launched about 30 years ago. The second phase with large-scale in-situ experiments called Disturbance and Re-colonization Experiment in a Manganese Nodule Area of the Deep South Pacific Ocean (DISCOL) (Germany) and Benthic Impact Experiment (BIE) (USA, Soviet Union, Japan, the international consortium Interocean Metall, and India), commenced their studies between 1988 and 1997. Results of these experiments and accompanying initiatives such as those of the German interdisciplinary advisory TUSCHgroup (from German Tiefsee-Umwelt-Schutz), are reported and discussed. In 2001 the International Marine Minerals Society published its " Code for Environmental Management of Marine Mining?? and during the Deep-Sea Minerals and Mining Conference in Aachen/Germany representatives of the mining companies Nautilus and Neptune reported collecting initial environmental baseline data in areas of future marine massive sulphide mining. Based on recent knowledge and experiences, recommendations for responsible environmental care related to deep-sea mining are described.

The United Nations Convention on the Law of the Sea (UNCLOS) places the responsibility for the environment on States for mining in exclusive economic zones (EEZs) and on the International Seabed Authority (ISA) for the exploitation of the resources in the Area, all regions beyond EEZs. Therefore, environmental regulations may develop independently and somewhat controversially. Harmonized directives should be strived for. From 1998 to 2007 the ISA has held several workshops in which different aspects of future mining of mineral resources were discussed. An overview is given here.
Evaluating the Loading and Structural Response of an Offshore Platform Using Integrated Large and Small Scale Testing Combined With Diffraction and Finite Element Analysis and Offshore Measurements
Authors: Buchner Bas , Heerink Robert , de Wilde Jaap , Witz Joel , la Cour Hjelholt Karen
Published: July 2009

After discussing the specific roles of model tests, simulations and offshore (full scale) measurements for the evaluation of offshore structures in general, the paper applies this integrated methodology to the investigation of the loading and structural response of the South Arne platform with the aim of extending the platform's capabilities. The South Arne platform deck is supported by a combination of a large volume concrete Gravity Based Structure (GBS) and a slender steel lattice structure. This resulted in a unique project, including the novel combination of small scale tests of the complete structure (GBS and lattice tower) with large scale component testing of parts of the lattice tower to limit and quantify scale effects on these slender members. The paper discusses the different phases (and scales) of model testing and also highlights the related Finite Element (FE) and diffraction calculations and offshore (full scale) measurements.

INTRODUCTION

In the process of evaluating an offshore structure during its design or while in operation, model tests, simulations and offshore (full scale) measurements all clearly complement one another (Figure 1). All three have their specific roles, strengths and limitations [1] which are summarised below.
SS: Exploration Prospect Interpretation and Risking Using Modern Geophysical Technology - Marine Applications of Highest Possible Resolution Imaging
Authors: Neidell Norman S. , Cuttell Andy
Published: July 2009

The classical CDP imaging method approximates a zero source-receiver offset view under each surface symmetry position for the sources and receivers used. Marine seismic surveys are inherently two-dimensional in nature. Nevertheless, there is bone fide diffractive information content. Imaging between different traverses relies solely on this diffractive component. Many migration methods treat such contributions in approximation..

A final CDP-based image can deliver good to excellent data quality. We investigate here the effect of parameters such as the number of data planes, separation of the planes, and other such factors on the resulting imaging character.

One particular imaging method is called the Highest Possible Resolution Seismic Image. In order to most effectively use the resulting extended spatial and reflection time resolution, a trace inversion is used to display seismic datat. Color presentations which significantly extend the visual dynamic range are also used. This allows better access to the full information content of the images. Examples will show these results and further enlighten geoscientists about basic seismic imaging considerations, with emphasis on resolution which have particular relevance to important applications such as 4D surveys.

Introduction

Classical CDP imaging approximates a zero source-receiver offset view under each surface symmetry position for the paired sources and receivers used. Marine seismic surveys however, are inherently two-dimensional in nature even when multiple streamers and sources are deployed. This character results from combining data acquired using parallel passes of the vessel.

There is bone fide diffractive information in marine data which is derived laterally, but away from the basic survey plane of each traverse. When we image subsurface locations between different traverses, we rely primarily on this diffractive content. If we formulate a travel-time relationship as a function of lateral offset, we can see how the image relates to those parameters about which we have some information - source position, receiver location, velocity, etc. In fact, most current migration methods do approximately correct for such contributions.

CDP Imaging methods can be effective despite using only reflective returns plus very limited diffractive components. The marine 3D final image can deliver good to excellent data that approaches the quality of full 3D imaging as on land for example, which has more diffractive contributions as well having a greater diversity of azimuths. We investigate here the effect of parameters such as the number of planes, separation of the planes, and other factors on the resulting imaging information content.
Future Vision: The Next Revolution in Production Operations
Authors: Bartram Mark A. , Wood Tony
Published: July 2009

In recent years there has been a proliferation of onshore control centres and advanced collaborative environments supporting the digitization of offshore oil and gas production. Information and communications technologies have facilitated this ‘digital’ evolution. To-date the results have been impressive, improved productivity and economics, together with health, safety and environmental benefits have been demonstrated. New advances in digital technologies are now poised to revolutionize how engineers and oil and gas professionals collate, visualize and interact with complex information, from real-time sensor data through to ‘fuzzy, asynchronous chat’ from instant messaging and other internet based communications tools.

This paper presents a review of how the next generation information and communication technologies are impacting complex, virtualized operations in industries such as the military. Case studies and lessons learned are presented together with insights and experience on how these findings can be applied to offshore production operations.
3D Petroleum Visualization: Workflows and Collaborative Solutions to Identify New Exploration Plays, Enhanced Reservoir Characterization and Improved Drilling and Wellbore Placement.
Authors: Love Frank , Purday Nicholas
Published: July 2009

Emerging plays, deeper zone exploration, along with complex reservoir development require the best possible workflows and collaborative solutions in today's competitive environment. The seismic amplitude play has been exhausted, today's E&P Companies must focus on the classic prospect and field elements of reservoir, trap, and charge. Deepwater field appraisal, development, and production operations increasingly require collaboration of multiple disciplines. This paper will evaluate how visualization workflows are used to de-risk reservoir presence and complexity. We will show how enhanced imaging tools and structural evaluation technology can further the understanding of trap risk and fault compartmentalization. How using 3D Petroleum Basin Modeling technology we can better predict charge potential, gas verses oil, and the presence of over-pressure. Enhanced geologic risk analysis through the use of 3D-Visualization workflows is essential to make commercial decisions in high cost deepwater and international settings. Reducing well count through better understanding of reservoir complexity and early prediction of reservoir performance can be enhanced through visualization technology. Of paramount importance to E&P Companies is safe drilling and risk reduction through the integration of geologic models with drill technology and pre-drill planning in a fully 3D environment. An integrated collaborative approach using visualization is increasingly needed to bring the basin wide knowledge into a single frame.3D-Visualization is no longer a game changer technology, but a necessary tool used by petroleum professionals. Companies which fail to fully adopt visualization technology are now at a disadvantage.
SS: Testing in the Offshore: Philosophies for dynamic positioning in ice-covered waters
Authors: Kuehnlein Walter L.
Published: July 2009

Approximately one third of the world's known and not yet exploited reserves of hydro carbons are in Arctic and Subarctic areas. Consequently, the offshore technology is going towards Arctic. New developments for operation in ice are generating new exiting challenges for offshore and ship building industries all over the world.

The paper describes the major challenges of dynamic positioned vessels in ice-covered waters. As the forces acting on vessels in ice and also their response are substantial different from the behavior in open waters, new philosophies and strategies have to be developed: How to keep vessels or offshore structures at a given position.

Based on model test results from HSVA the paper explains the main challenges of dynamic station keeping in ice and describes the consequences on station keeping philosophies and strategies for ships and offshore structures in ice. As up to now no dynamic positioning system exists for ice covered waters the paper illustrates a new approach in order to reach this goal.

The paper gives by far not a complete description of dynamic positioning of vessels in ice. But it summarizes where we are and what needs still to be done.

Introduction

It is estimated that the Arctic contains more than one third of the world's undiscovered oil and gas reserves. Although some development has already been undertaken, the region remains one of the last energy frontiers. At the same time, the region is also one of the most difficult areas in the world to work in, due to its remoteness, the extreme cold, dangerous sea ice, and its fragile environment. Major energy companies are already getting prepared to get into the Arctic, taking precautions to operate safely and responsibly.

This is not the first run to the Arctic. Petroleum companies entered into the Arctic already half a century ago. Experiences from past Arctic developments show the potential hazards of further exploration in the area. A key challenge will be developing and deploying solutions, which are currently at the cutting edge of technology. The Arctic Ocean is the only major sub-basin of the world's oceans that has only occasionally been sampled by deep sea drilling. Today the properties of the Arctic Ocean are being focused upon by both researchers and commercial oil and gas drilling companies. Research core drilling is of great importance for the researchers because it allows them to increase their knowledge about that large ice covered area. And, of course, high energy prices in the future, similar to the ones we have already seen during last summer, make it profitable to explore for reserves and to produce energy even in the ice covered waters of the " High North??.
Ormen Lange Subsea Compression Pilot System
Authors: Bjerkreim Bernt , Frydenlund Snorre , Lie John Arild , Staver Knut Ola , Haram Karl Olav , Nystad Bjørn , Skofteland Håkon , Gedde Hans , Tesei Alberto , Postic Michel
Published: July 2009

Ormen Lange is a long tieback gas field developed with gas processing facilities onshore 120 km from the production wells. The development strategy is pressure depletion. In order to maintain the production plateau for as long as possible and recover the anticipated gas and condensate resources, offshore compression is required to maintain production.

This paper describes subsea compression as a cost effective alternative to the platform compression solution and the strategy for qualifying subsea compression system prior to offshore compression concept selection.

This paper further describes the subsea compression technical solution.

Introduction

Ormen Lange is a gas field located 120 km off the northwest coast of Norway on the Norwegian continental shelf, in water depths varying between 850 and 1,100 meters. The reservoir covers an area 40 km long, 8 to 10 km wide and 3,000 meters below the surface. Recoverable reserves are estimated to approximately 397 billion Sm3 dry gas and 28.5 million m3 condensate. Ormen Lange has been in production since October 2007.
Ormen Lange Subsea Compression Pilot - Subsea Compression Station
Authors: Skofteland Håkon , Hilditch Mike , Normann Truls , Eriksson Klas Goran , Nyborg Knut , Postic Michel , Camatti Massimo
Published: July 2009

Aker Solutions is the main contractor for the engineering, procurement, construction and installation of the subsea compressor station being built as part of the Ormen Lange pilot project. The compression station pilot is a full scale 12.5 MW compressor train which is equal to one of the four trains required for the permanent subsea compression station for the Ormen Lange gas field.

This paper describes the system design, equipment and subsea technology developed for the compression station pilot. The main part of the project has been to design equipment and technology fit for installation at 900 meters water depth and to ensure that the stringent requirements for reliability and robustness are fulfilled.

The process system is exposed directly to the wellstream at Ormen Lange and is designed to handle varying gas-condensate rates, liquid slugs and sand production. The main process equipment is the separator, compressor, pump and cooler. The high voltage power distribution system includes subsea circuit breakers, subsea transformers and frequency converters to drive the subsea compressor and pump. The electrical equipment is included in subsea enclosures with high voltage mating mechanisms between the units.

The control system is key component for the subsea compression station. The long tie-back of 120 km and the requirement for high speed closed loop control and high bandwidth communication to shore initiated development of new technology solutions. An all electrical control system is developed with subsea uninterruptible power supply and electrical actuators. A SIL2 rated Process Shut-Down System (PSD) is also included for additional protection of the subsea components. Communication subsea to shore is via fibre optic lines in the power umbilical.
Optical Permanent Monitoring System Meets the Subsea Challenge
Authors: Shand Michael M. , Birch Michael Charles , Bostick Tad , Tough Gary
Published: July 2009

In-well monitoring systems have now been developed which utilise permanent optical fibre sensing and can be deployed in the subsea environment. These optical monitoring systems are well suited for subsea deployment in terms of extended temperature and pressure regimes, along with reliability and advanced optical multiplexing technology.

Hundreds of optical sensors and millions of feet of optical cable have been successfully deployed in land and dry tree platform oil and gas wells since the early 1990's. In the last 1990's, a few prototype optical sensing systems were deployed subsea for single point pressure and temperature monitoring with partial success. However, over the last 10 years, optical sensing technology has progressed significantly, yet no subsea installations have been performed. This was not due to lack of interest but to significant challenges related to subsea deployment, and also in part due to projects cancelled for such reasons as perceived lack of data delivery infrastructure.

This paper describes how the significant challenges of subsea optical sensing were overcome through close cooperation between the operator and other 3rd party companies, along with extensive project organisation, custom engineering, and qualification testing and system verification. Deployment of the system took place offshore Angola in Q1 2008.

The major areas which we addressed in order to assure success were:Establishing standards to which the subsea instruments and components should comply with in order to build a robust test regime for qualifying the new optical sensing technology.Developing, qualifying and interfacing a subsea connector system for wellhead and tubing hanger penetration.Developing, qualifying and interfacing a new generation subsea optical instrument which would be deployed subsea in an atmospheric housing.Designing an in-well monitoring system which can deliver accurate reservoir pressure and temperature data from the sand-face to surface.
SS: Arctic: LNG STS Operations in Arctic Waters
Authors: Berg Tor Einar , Bakke Joachim
Published: July 2009

The LNG market is expanding, and development plans exists for LNG processing plants in Arctic Russia. This paper discusses a possible transport chain for LNG produced at shore-based terminals on the Yamal Peninsula. The recent disagreement between Russia and Ukraine on gas export to Europe has demonstrated the vulnerability of the present overland export system for natural gas. The planned North Stream will increase energy security for several European countries. However, a sea transport system may create a win - win situation for Russian gas producers and world-wide customers of natural gas.

The first part of the paper describes the individual legs of the proposed transport chain. The second part discusses ship-to-ship transfer of gas in general, followed by a review of LNG ship-to-ship transfer, and ends with a specific case, of which high-seas ship-to-ship transfer in Arctic waters is a critical element. The final part of the paper describes necessary developments in cargo-handling equipment and operational procedures for LNG transfer between two large LNG vessels in Arctic waters.

Ship-to-ship transfer of oil and gas is a routine operation in many parts of the world. A cost-effective transport system from Arctic LNG plants in the western part of the Russia to markets in Western Europe and east coast US/Canada could be achieved through the use of dedicated icebreaking LNG tankers transloading their cargo to conventional LNG carriers in ice-free waters in the Barents Sea.

1 Introduction

With the expected increase in demand for oil and decrease in production in certain areas in 2010 - 2020, pressure to develop the Arctic region is growing. The extreme conditions with ice and very low temperatures will make even more stringent demands of the ships, equipment and crew than normal. The Arctic is particularly sensitive and vulnerable, and the vision of zero harmful discharges is now generally accepted. A sharper focus on the part of IMO, EU and Arctic organizations, on environmental issues and safe operations will influence vessel operation. There will be a focus on new and innovative costeffective solutions to satisfy the strict requirements for ships and equipment from ship-owners, class societies, operators, the authorities and other stakeholders. The development of the Snøhvit gas field with its Melkøya LNG terminal has moved offshore gas production far north. Much larger offshore and onshore fields exist in the Russian sector of the Barents Sea and on the Yamal Peninsula. The recent problems with Russian gas export to Europe may increase pressure to develop an independent sea export route from the Russian European Arctic in addition to the planned North Stream pipeline. Current plans for development of LNG plants include a plant in Teriberka, where the Shtokman gas will be landed, and a facility on the Yamal Peninsula. Ship-based export from these plants will give the Russian gas company Gazprom access to both the European and North American markets.
Deepwater BOP Control Monitoring - Improving BOP Preventive Maintenance with Control Function Monitoring
Authors: Chapman Frank M. , Brown Ronald L.
Published: July 2009

The goal of Blowout Preventer (BOP) preventive maintenance is to reduce downtime due to equipment failures. A corollary issue is the reduction of unnecessary maintenance. This becomes increasingly important as the BOP control system ages or nears its five-year maintenance cycle.

Appropriate / timely proactive BOP maintenance can only be performed when accurate function cycle data is available. As such, an effective BOP preventive maintenance program requires accurate record keeping on all BOP function cycles - during drilling operations as well as during testing. Manual record keeping is generally missing or unreliable.

A system has been developed for (1) automatically monitoring and recording BOP control state changes, (2) transporting the state change data to a database server on shore and (3) analyzing and presenting the BOP information to interested personnel via the web. The system provides a detailed historical record of the BOP status. Using this data the number of valve cycles can be accurately counted and the valve cycle information can be used to estimate when maintenance is required for each valve in the BOP control system.

In addition, the information captured by the system can be used to troubleshoot BOP control issues and as input to evaluate BOP operational procedures.

Introduction

Proper maintenance of a rig's BOP is critical for insuring the safety of offshore drilling operations. In many regions of the world regularly scheduled BOP testing is a regulatory requirement. Unexpected BOP problems or failures can lead to significant downtime [Holand 1997, Holand 1999]. Fixing BOP problems can be extremely expensive, particularly if the problem or failure requires the marine riser and BOP to be round tripped. The various valves contained in a BOP control system and the number of times they are cycled is a significant factor affecting BOP reliability [Shanks 2003].

New technologies can be used to continuously and accurately monitor BOP operations over time. Having accurate historical information on BOP operations, valve cycles and pressures can lead to more proactive BOP maintenance programs. Better maintenance can, in turn, result in safer operations and reduced costs.

Over the years a number of new technologies have been integrated into offshore drilling programs. In most cases these technologies have resulted in improved operations and reduced expense. In many cases the next step to achieving improved operations and greater cost reductions is to integrate several existing technologies.
Qualification of LNG STS transfer flexibles according to guideline EN1474-II
Authors: Van den Beemt Bas , van Bokhorst Evert , van der Weijde Gerard D. , Mallon Niels , Verweij Sander
Published: July 2009

This paper will describe some lessons learned from the qualification process of 8?? cryogenic multi composite hoses for ship-to-ship transfer of LNG. The available guideline for certifying transfer hoses is the EN1474-II. In addition to this guideline, which was preliminary at the time of use, many other issues need to be detailed and until now leave room for further interpretation.

TNO proposed a multilevel test program combined with developing models that predicts the behavior of the hose system. The test program showed some remarkable results related to the mechanics of the hose. For example the hysteresis provides a damping mechanism for vibrations due to internal and external sources. Also extreme high damage tolerance behavior, in incidents the hose provides a high level of residual safety. The remaining burst pressure is still exceeding the burst pressure requirements of an undamaged hose and no jetting occurs.

With a full scale LNG flow test the flow behavior of the hose is extensively tested. For example the maximum flow of 1500 m3/h has been shown during this test and did not lead to unacceptable pulsation or vibration levels. The prediction model for the friction factor of the 8-inch hose, based on tests at ambient temperature with water, shows the correct trend. The pressure loss depends on the internal pressure in the LNG flow test, which shows the added value of this LNG Flow test.

The gained experience let to a number of recommendations for other LNG qualification projects. For example we recommend to combine tests with analyses to reduce the amount of testing for the complete transfer system and to be able to reapply the result for other configurations. Further specification of requirement than what is described in the EN standard is needed (e.g. excessive vibrations, what is stiffness, permeability). As long as further specification of the test is not provided in standards involvement in the definition of the test program of equipment supplier, end user, certifier and independent research contractor is needed. Finally the results proved that LNG test are still inevitable for flow equipment qualification and model validation.

Introduction

Dynamic transfer of LNG from ship-to-ship is seen as one of the enabling technologies to support a possible LNG supply chain offshore. LNG supply to regasification vessels or the offloading of a floating LNG production unit in the near future must be able to be performed under all weather conditions. The latter has made it necessary to develop alternatives to rigid loading arms, with an additional need for testing and certification. New transfer technologies and methods have to guarantee maximum terminal availability without making concessions to safety and operability. This paper will describe some lessons learned from the qualification process of 8?? cryogenic multi composite hoses for ship-to-ship transfer of LNG.
Tyrihans Subsea Raw Seawater Injection System
Authors: Grynning Audun , Larsen Stein Vegar , Skaale Inge
Published: July 2009

StatoilHydro's Tyrihans field development is located about 22 miles (35 km) south of the Åsgard field on the Norwegian continental and the oil production will be substantially increased by raw sea water injection.

The Tyrihans water injection system, currently manufactured and successfully tested, is the worlds most powerful subsea pump system and will have the longest step-out distance of 19.3 miles (31 km) to date. Two centrifugal pumps operate in parallel and have been verified by testing to be able to deliver a total shaft power of 7,340 hp (5.4 megawatts). The maximum injection capacity of the pumps is 126,000 bpd (20,000 m3/d) of seawater, without any filtration or chemical injection.

During the last year, the subsea pump system has been through full load performance, endurance, stability and system integration testing at Tranby, Norway. The paper presents the pump system design including the pump modules, barrier fluid system, power supply, control and monitoring system. Data from the performance testing is included and discussed.

System overview

The StatoilHydro operated Tyrihans field is located on the Norwegian continental shelf approximately 22 miles (35 km) south of the Kristin and Åsgard B Platforms. Tyrihans will be developed with 5 subsea templates including oil production, gas injection and one raw seawater injection template (W). The subsea production system will be tied back to Kristin through a 16/18?? oil production flowline and receive gas for injection from Åsgard B through a 10?? gas injection flowline.

Aker Solutions delivers the subsea raw seawater pump system and FMC was awarded the contract for the Subsea Production System for Tyrihans. StatoilHydro's contract strategy was to award this contract prior to awarding the contract for SRSWI and to invite the prequalified pump system suppliers to tender a pump system that could be lowered into the dedicated water injection template and controlled by the standard production control system.