Diving Support Vessel Research Articles

A review of accelerated decompression from heliox saturation in commercial diving emergencies.

Saturation diving is a specialised method of intervention in offshore commercial diving. Emergencies may require the crew to be evacuated from the diving support vessel. Because saturation divers generally need several days to reach surface, the emergency evacuation of divers is based on dedicated hyperbaric rescue systems. There are still potential situations for which these systems cannot be used or deployed, and where an emergency decompression provides an alternative solution. Our objective was to describe historical cases and assess the benefit of emergency decompressions, with the collection of data from the authors' direct experience and networks, providing witness or first-hand information. We documented three cases of emergency decompression following bell evacuations, and six cases of accelerated decompression performed in the chamber or hyperbaric rescue chamber. Review of these cases showed: 1) the complicated nature of such emergencies that make decisions difficult; 2) the variety of solutions implemented; and 3) the surprisingly safe and successful outcomes of several operations. Analysis of the accelerated decompression occurrences allowed derivation of the options used; upward initial excursion, increased chamber partial pressure of oxygen associated to increased ascent rates, and inert gas switching. We identified four published procedures for accelerated decompression. Despite modern hyperbaric rescue systems, accelerated decompression remains an essential tool in case of emergency. The diving industry needs clear guidance on what can be achieved, depending on the saturation depth and the level of emergency.

Vascular Function Recovery Following Saturation Diving.

Background and Objectives: Saturation diving is a technique used in commercial diving. Decompression sickness (DCS) was the main concern of saturation safety, but procedures have evolved over the last 50 years and DCS has become a rare event. New needs have evolved to evaluate the diving and decompression stress to improve the flexibility of the operations (minimum interval between dives, optimal oxygen levels, etc.). We monitored this stress in saturation divers during actual operations. Materials and Methods: The monitoring included the detection of vascular gas emboli (VGE) and the changes in the vascular function measured by flow mediated dilatation (FMD) after final decompression to surface. Monitoring was performed onboard a diving support vessel operating in the North Sea at typical storage depths of 120 and 136 msw. A total of 49 divers signed an informed consent form and participated to the study. Data were collected on divers at surface, before the saturation and during the 9 h following the end of the final decompression. Results: VGE were detected in three divers at very low levels (insignificant), confirming the improvements achieved on saturation decompression procedures. As expected, the FMD showed an impairment of vascular function immediately at the end of the saturation in all divers but the divers fully recovered from these vascular changes in the next 9 following hours, regardless of the initial decompression starting depth. Conclusion: These changes suggest an oxidative/inflammatory dimension to the diving/decompression stress during saturation that will require further monitoring investigations even if the vascular impairement is found to recover fast.

FORCED OSCILLATIONS OF FLEXIBLE PIPELINES ON SEA SURFACE WAVING

In offshore maintenance of oil platforms, a great number of technological processes on offshore fleet vessels (Diving Support Vessel, Construction Ship, Support and Supply Vessel) directly relate to the operation of flexible pipelines. Flexible pipelines are frequently used - from working fluids and fuel feeding to towing various surface and submersible craft. In some cases, in heavy seas, the flow velocities through the flexible pipeline can be very high. Ultimately, this will always lead to dangerous forced oscillations of the flexible pipeline that is used.

Risk assessment of ships collision during installation of anode protection on subsea gas pipeline located in Surabaya West Access Channel

Subsea pipeline is one of alternatives to transport gas from offshore platform to onshore production facility. In Surabaya West Access Channel (APBS), there are some subsea gas pipelines lay on seabed. Maintenance of subsea pipeline should be carried out to ensure the sustainability of gas delivery, such as replacement of Sacrificial Anode Cathodic Protection. Since the replacement activity includes operation of Diving Support Vessel (DSV) along the subsea pipeline, it could potentially induce ship collision between DSV with other ships passing through the channel. This paper carried out a risk assessment of ship collision during replacement of anodes of subsea gas pipeline in APBS. The frequency of ship collision is analyzed by using Computerized Risk Assessment of Shipping Hazards (CRASH) and Traffic Based Models. The consequence is analyzed using Finite Element Method (FEM) which results the impact of collision on the hull of ship. Deformation of hull requires cost of repair which further becomes the outcome of consequences analysis. The risk is represented in the risk matrix which adopted from the Australian Standard Guidelines. The result shows that frequency of collision is 0.1342 per year while the consequences analysis results US$ 2,160,077 which required for repair. The risk representation shows that the anodes replacement has an extreme risk level based on the Australian Standard Guidelines. Further preventive measures are required to reduce the level of risk to be medium or low level of risk.

Evaluation of Divers' Neuropsychometric Effectiveness and High-Pressure Neurological Syndrome via Computerized Test Battery Package and Questionnaires in Operational Setting.

Introduction: When divers are compressed to water depths deeper than 150 meter sea water (msw), symptoms of high-pressure neurological syndrome (HPNS) might appear due to rapid increase in pressure on the central nervous system during compression. The aim of this study was to first operate a new computerized tool, designed to monitor divers’ wellbeing and cognitive function, and to record the results. The second aim was to evaluate the feasibility and validity of the Physiopad software and HPNS questionnaires as a new tool for monitoring divers wellbeing in an operational setting, including sensible visualization and presentation of results.Methods: The Physiopad was operated onboard Deep Arctic (TechnipFMC Diving Support Vessel). The diving work was performed between 180 and 207 msw. The data from 46 divers were collected from the HPNS questionnaires, Hand dynamometry test, Critical Flicker Fusion Frequency test (CFFF), Adaptive Visual Analog Scale (AVAS), Simple Math Process (MathProc test), Perceptual Vigilance Task (PVT), and Time Estimation Task (time-wall).Result: Diver’s subjective evaluation revealed different symptoms, possibly also HPNS related, which lasted from 1 to 5 days in storage, with the common duration being 1 day. The results from Physiopad battery testing showed no signs of significant neurological alteration.Conclusion: The present study showed that there was no association between subjective measurements of HPNS and neuropsychometric test results. We also confirmed the feasibility of using the computerized test battery to monitor saturation divers at work. The HPNS battery and Physiopad software could be an important tool for monitoring diver’s health in the future. This tool was not used during the Bahr Essalam project to operationally evaluate any HPNS effect on divers as data analysis was performed post-project.

Alternating current and direct current-based electrical systems for marine vessels with electric propulsion drives

The initial widespread electrification of marine vessels primarily used alternating current (AC)-based systems as they were prevalent in the electrical distribution infrastructure for land-based systems. At present, there are marine vessels that operate based on a hybrid diesel-electric system, in which the on-board diesel engines generate AC power to a common AC bus, which in turn supplies power to the electrical propulsion drives and other service loads. Recently, there has been an active interest in a transition to direct current(DC)-based electrical distribution system with diesel-electric hybrid propulsion systems for marine vessels due to potential improvements in electrical performance and fuel consumption. This paper evaluates the improvement in the move to DC-based distribution system for marine vessels in terms of electrical performance and fuel efficiency. An overview of a typical AC electrical system currently in use is provided, and modifications of the system to a DC-based system is presented. The power factor, total harmonic distortion, and voltage regulation are discussed. Both symmetrical and asymmetrical generator scheduling are examined and the potential fuel savings for an example diving support vessel is presented. A discussion on the recommendations to shift towards DC-based systems is then provided based on the findings of this paper.

Automatic Optimization of Oilfield-Scale-Inhibitor Squeeze Treatments Delivered by Diving-Support Vessel

Summary Oilfield-scale deposition is one of the important flow-assurance challenges facing the oil industry. There are a number of methods to mitigate oilfield scale, such as reducing sulfates in the injected brine, reducing water flow, removing damage by using dissolvers or physically by milling or reperforating, and inhibition, which is particularly recommended if a severe risk of sulfate-scale deposition is present. Inhibition consists of injecting a chemical that prevents the deposition of scale, either by stopping nucleation or by retarding crystal growth. The inhibiting chemicals are either injected in a dedicated continuous line or bullheaded as a batch treatment into the formation, commonly known as a scale-squeeze treatment. In general, scale-squeeze treatments consist of the following stages: preflush to condition the formation or act as a buffer to displace tubing fluids; the main treatment, where the main pill of chemical is injected; overflush to displace the chemical deep into the reservoir; a shut-in stage to allow further chemical retention; and placing the well back in production. The well will be protected as long as the concentration of the chemical in the produced brine is greater than a certain threshold, commonly known as minimum inhibitor concentration (MIC). This value is usually between 1 and 20 ppm. The most important factor in a squeeze-treatment design is the squeeze lifetime, which is determined by the volume of water or days of production where the chemical-return concentration is greater than the MIC. The main purpose of this paper is to describe the automatic optimization of squeeze-treatment designs using an optimization algorithm, in particular particle-swarm optimization (PSO). The algorithm provides a number of optimal designs, which result in squeeze lifetimes close to the target. To determine the most efficient design of the optimal designs identified by the algorithm, the following objectives were considered: operational-deployment costs, chemical cost, total-injected-water volume, and squeeze-treatment lifetime. Operational-deployment costs include the support vessel, pump, and tank hire. There might not be a single design optimizing all objectives, and thus the problem becomes a multiobjective optimization. Therefore, a number of Pareto optimal solutions exist. These designs are not dominated by any other design and cannot be bettered. Calculating the Pareto is essential to identify the most efficient design (i.e., the most cost-effective design.)

Investigating the reliability and criticality of the maintenance characteristics of a diving support vessel

Maintenance tasks and their application in the shipping industry have evolved significantly in the recent years. Particularly in the offshore industry, safety onboard, environmental protection and intensive operational activities necessitate the minimization of down-time and the preservation of an excellent performance ratio. The first step of an innovative ship maintenance strategy, which is proposed by the authors and is based on criticality and reliability assessment, is presented herein using the FTA tool with time-dependant dynamic gates so as to represent in an accurate and comprehensive way the interrelation of the components of a system. The paper also presents a review of the maintenance standards and procedures, such as the ALARP concept, the Key Programme 3-Asset Integrity (KP3) initiative, the OREDA handbook as well as the RCM and RBI principles. As part of the reliability assessment, the Birnbaum and Criticality reliability importance measures are utilized to validate the results of the analysis. A case study of a diving support vessel (DSV) illustrates the application of this strategy. The main systems examined are: the vessel's power plant, propulsion, water system, lifting, hauling and anchoring, diving and finally the safety system. The reliability of the main systems and subsystems as well as of their critical components is identified and suggestions of how to improve the overall reliability of the various systems both at a component, system and managerial level are also proposed. Copyright © 2011 John Wiley & Sons, Ltd.

South Arne-Nybro Offshore Pipeline—The Subsea Installations

A summary is given for the design and construction of the South Arne-Nybro 24-in. gas pipeline. The main design requirements for the subsea installations are presented: subsea Wye piece configuration to enable gas export from both South Arne and Harald, use of subsea safety valves close to platforms, platform-based control systems for opening of subsea check valves, subsea ball valves and small bore ports for precommissioning, pipeline isolation and contingency purpose, strong protection structures to avoid damage by fishing gear, and, finally, design to avoid scour problems. The design work to achieve these objectives as well as simple installation methods for the subsea assemblies by use of a medium-sized diving support vessel is described. An outline for the offshore construction work is finally given.

Novel Wax-Diverter Technology Allows Successful Scale-Inhibitor Squeeze Treatment in a Subsea Horizontal Well

Summary In this article we present field results from two scale squeeze treatments carried out on the same subsea horizontal well from the Strathspey field in the North Sea. The initial squeeze was a bullhead application of phosphonate scale inhibitor to control a sulfate scale problem in a horizontal well. Ten months after the initial treatment a second bullhead squeeze treatment was applied in two stages. This latter utilized a thermally degraded pelleted wax diverter to temporarily impair the injectivity in the heel region of the horizontal well thus allowing propagation of the second stage of the squeeze treatment into the midsection of the horizontal well. In this article we show the significance of production logging tool data to evaluate the location of deposited scale and water production prior to a squeeze treatment. These data were used to design a novel two stage squeeze treatment in which an initial squeeze slug was applied to the heel region followed by application of a pelleted thermally degraded wax diverter to prevent further loss of scale inhibitor to the heel region. The action of the wax diverter allowed a second scale inhibitor slug to be placed further along the horizontal section of the well. Details of the diverter selection and the squeeze design strategy implemented in this squeeze treatment will be presented. During the field treatment, physical (downhole pressure and temperature) data and chemical (nonradioactive tracers, inhibitor and ion concentrations) data were recorded. These data will be used to indicate the success of the diversion treatment by a comparison with the first squeeze applied to the same well 10 months previously. This is the first successful application of a thermally degraded wax diverter to a subsea horizontal well in the North Sea basin. The well was successfully treated with no process upset during flowback and no decline in well production while allowing the well bore to be protected from continued sulfate scale formation. In this article it is clearly shown that with the correct selection of both the scale inhibitor and diverter agent together with ulitization of all available information relating to the reservoir, it is possible to squeeze scale inhibitors into subsea horizontal wells without the need for intervention by expensive coiled tubing from a diving support vessel.

Korrosionsüberwachung an Schiffen und in der Meerestechnik

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Diving Support Vessel Concept Design

This paper describes the preliminary process for designing a 250 ft dynamically positioned, Diving Support Vessel. This is to serve the offshore oil industry as a platform for underwater intervention. Enlisting the use of the latest technological advances, the vessel will support both remotely operated vehicles and human divers. We will trace the development of this design with a well-defined agenda. Beginning with an analysis of the existing fleet, a practical hull form is created, which leads to solid estimations for hydrostatics, stability, resistance, powering and preliminary arrangements. We will also discuss the steps that will follow over the next several months.

The Highlander Field - One Year's Operating Experience

Summary In 1985 the Highlander field was brought on stream from one of the first generation of advanced remote-controlled subsea production facilities in the North Sea only 15 months after the U. K. Dept. of Energy approved development. The successful development of the Highlander field was made possible by a combination of innovative ideas and the advancement of existing technology. This paper describes the problems and successes during 1 year of operating experience. Introduction The Highlander field is located in Block 14/20, 8 miles [12.9 km] northwest of the Tartan platform in 420 ft [128 m] of water (Fig. 1). Because "stand-alone"-type developments were seen as uneconomical, the decision was made to develop the field with a remote-controlled subsea production and water-injection facility would be controlled by and produced to the Tartan platform. The development was completed in two phases, a procedure that substantially reduced the time from project approval to first oil being produced. Phase 1 consisted of running well completions in predrilled, offtemplate wells and connecting these wells to the Tartan platform through two 8-in. [200-mm] service lines. During Phase 2, the template and slug catchers were installed; the wells were reconnected to the template; and the template, test and bulk production pipelines, slug catchers, and risers were commissioned. These two phases are described more fully by Smith and Batcheler. This paper deals with the operating experience of Phase 2. The development originally consisted of four wells-Wells HS12, HS13, HS14, and HS15-previously drilled and suspended between 1980 and 1983. In 1985, these wells were completed and tied into a subsea template that has 12 additional slots for future wells. Since then, three wells (Wells H1, H2, and H3) have been drilled successfully through the template. All wells and services are interconnected by manifolds on the template. Production to the Tartan platform is through 12-in. [300-mm] bulk and 8-in. [200-mm] test multiphase pipelines. The pipelines are connected into two subsea slug catchers at the base of the Tartan platform. These slug catchers are designed to eliminate slugging before oil is pumped up to the platform through two 7-in. [180-mm] casing strings. Gas is separated out of the crude at the slug catchers and routed to the platform through the 18 5/8x7-in. [470X180-mm] riser annuli. The template is also connected to the Tartan platform by 8-in. [200-mm] waterinjection, 8-in. [200-mm] gas-lift, and 4-in. [100-mm] utility flowlines. Umbilicals provide hydraulic and electrical power and chemical injection to the template. Maintenance is by diver intervention during well servicing, and workovers require a diving support vessel or semisubmersible drilling rig. A new subsea wireline technique, successfully tested on Well HS14 in Nov. 1987, allows routine well work to be carried out from either a diving support vessel or a semisubmersible drilling rig simultaneously with the drilling of new wells. This will substantially reduce well-servicing costs.

Operation and Reliability of a North Sea Floating Production System

Summary This paper describes the reliability and operating history of the U.K. Continental Shelf (UKCS) Block 30/24 floating production facility. The equipment and techniques in use result from experience gained and technologies developed in more than 12 years of operating floating production systems in the harsh production systems in the harsh North Sea environment. This paper discusses the performance of these systems and presents an uptime analysis to quantify the effect of various components on overall efficiency. Introduction UKCS Block 30/24 is located 200 miles [320 km] offshore in the central sector of the North Sea. The Argyll, Duncan, and Innes fields are currently on production from this block. The Argyll field provided the first oil production in the UKCS. The semisubmersible production in the UKCS. The semisubmersible drilling rig Transworld 58 was converted to the industry's first floating production facility, and production was started through subsea wells on June 11, 1975. Crude processed by the Transworld 58 was exported by a catenary-anchor-leg-moored (CALM) buoy and shuttle tankers. The Duncan field, 4 miles [6.5 km] west of Argyll, was discovered in late 1980. A subsea manifold installed between the Duncan and Argyll fields gathered production from four Duncan field satellite wells for transportation of the combined production stream to the Transworld 58. In Oct. 1984, waterflooding to maintain Duncan reservoir pressure dictated the replacement of the pressure dictated the replacement of the Transworld 58 by the floating production facility Deepsea Pioneer. This unit has a waterflooding plant for Duncan and a gas-lift plant to sustain Argyll production. In Jan. 1985, the Transworld 58 began production from the Innes field, 8 miles [13 production from the Innes field, 8 miles [13 km] north of Argyll. The crude oil was exported through the Argyll CALM buoy and shuttle tankers. By Dec. 1986, the Innes field proved to be of limited extent and unable to support a stand-alone facility. The two Innes wells were tied back to the Deepsea Pioneer, eliminating the need for the Transworld 58. Fig. 1 illustrates the current physical arrangement of the Block 30/24 production system. Twelve subsea production wells from three different fields, all with differing fluid characteristics, are routed back to a central manifold by individual flowlines or by remote manifolds and feeder flowlines. The crude is separated on a single floating production facility and stabilized. Crude is exported by a CALM buoy and shuttle tankers. Production Performance Production Performance (Uptime Analysis) Production uptime is often stated as simply Production uptime is often stated as simply the percentage of time that production is flowing through the process train with no allowance made for either restricted production rates owing to equipment malfunction production rates owing to equipment malfunction or limited availability of individual wells. Using this approach, operators routinely achieve more than 95% uptime. This simplified approach is not adequate to evaluate the operational performance of a producing system as complex as that in Block 30/24. The concept of uptime was used to identify areas where the overall efficiency of the system could be improved. We have generated a data base for the system that relates uptime to the individual aspects of the overall production system. All the data used in production system. All the data used in the system are based on a well-hour time analysis. One well-hour is accrued to the data base for every hour that a well is available for production. A well is considered available for production unless closed in for a workover or major flowline repair. Lost production time is identified according to one of five major categories:Field-specific downtime is lost time that does not result directly from a failure of the offshore production facilities. It reflects production time losses associated with production time losses associated with work-overs, downhole mechanical problems like safety-valve failures, and subsea flowline leakages. This time is a direct result of problems that cannot be rectified by personnel problems that cannot be rectified by personnel on the floating production facility or field diving support vessel (DSV) without the intervention of a drilling rig or the acquisition of replacement items, such as new flowlines.Weather downtime reflects well hours lost to severe weather and seastate.Loading-buoy downtime describes well hours lost to tanker changes and any CALM-buoy-related problems or repairs.Production-plant downtime reflects well hours lost to process plant problems, as well as plant shutdowns associated with emergency shutdowns or other plant problems. problems. 5. Major project downtime includes all large items of work that involve planned shutdowns, such as the installation of gas-lift facilities or the Deepsea Pioneer. Several constraints affect the percent production uptime that can be achieved with the production uptime that can be achieved with the Block 30/24 system. JPT P. 1336

An Operational Subsea Wireline System

This paper describes an operational subsea wireline system that is self-contained and flexible and offers a safe, economical, and proven method for riserless re-entry into any subsea well. The system discussed here was developed over a number of years and has been used to carry out a comprehensive range of wireline tasks from floating vessels in the North Sea. Although generally deployed from a diving support vessel (DSV), the system has been successfully used from a drilling rig to conduct wireline operations in a well, simultaneously with workover operations in an adjacent well, on a subsea template.