Sakhalin-1: Technology Development for Frontier Arctic Projects

Ice loads on the design waterline (DWL) of several vessels were computed with the program Venice to obtain ice load distributions on ship hulls advancing straight ahead in level ice. The purpose is to obtain the spatial distribution of ice loads on the ship hulls in level ice, including the information on how the ice loads vary as functions of ship speed or ice thickness. For one ship hull the computed ice loads were compared with ice load distributions measured in model scale. The computed distributions were also compared with the design line load distributions used in the Finnish-Swedish ice rules and in the Polar Class rules. Some clear differences were found.

Existing national and international standards for determination of level ice and ice ridge loads on sloping offshore structures recommend different methods for the analysis. The objective of this paper is to review the codes and standards recommendations regarding ice-sloping structures interaction process and highlight the differences between them. Development of offshore hydrocarbon fields in the Eastern Barents Sea is foreseen to take place in the near future while developments already take place in the Pechora Sea and offshore Sakhalin as well as in the Northern Caspian Sea. One of the most difficult issues facing the designer of offshore structures for these areas is how to design for loads from level ice and ice ridges. The ice load considerations will have a major effect on the form and cost of these structures. It is known that different designers use very different ice load estimates (Shkhinek et al., 1994). The standards recommend different methods for determination of the global ice loads on both cone-shaped and sloping rectangular structures. For determination of the global ice loads on these types of structures, it is obvious that the ice-structure interaction process must be identified. Rubble effects must be included in the analysis. The ice-structure interaction process for these geometries depends on many factors, such as; the ice thickness, ice strength, ice-structure friction coefficient, ice velocity, width of the structure and slope angle of the structure. The methods for determination of ice loads recommended by the different standards are very much influenced by local ice conditions and the parameters listed above are given different importance in the different standards. The differences in loads calculated by using the different standards and their validity for the ice-structure interaction process have been investigated and example calculations are presented to show these differences. It is thought that the paper may be of interest for those preparing the new ISO standard (ISO 19906) on Arctic Offshore Structures.

Ice loads, due to large absolute values and diversity, are most important for the calculation of Arctic marine and river structures. The cost of the structure being designed may change several times with a change in the design ice load; therefore, determining the ice load of a given probability is an important task. Some ice formations can significantly change the value of the ice load, but they are not present in the normative documents and standards. Ice collars can be described as thicker ice around heat-conducting structures, which can lead to an increase in loads. However, there is not any method for calculation of ice collar influence on the loads present in the current documents. Ice collar is the reason for thicker ice at the structure-ice contact surface, which lead to an increase in the contact area and can lead to a change in the mechanism of ice failure. In some cases, the presence of an ice collar leads to an increase in the horizontal ice load from the level ice on the structure. The method of discrete elements is considered to solve the problem of the influence of the ice collar on the ice loads. This method allows a time-dependent description of the entire process of destruction of the ice collar. Two-dimension settings are used in vertical and horizontal planes. The relative ice load depending on the thickness of the ice and freezing-degree-days are obtained.

Ice-capable jackups can offer mobility and efficiency while drilling in shallow, ice-infested waters. However, the industry has limited experience operating jackups in ice environments, and technology gaps and uncertainties remain when assessing ice loads on multi-legged jackup units. The Graphic Processing Unit (GPU)-based Discrete Element Method (DEM) can be applied to investigate the degree of ice effects on multi-legged jackup units. In previous applications, the DEM method was used to simulate ice interaction with structures, but computations were limited to simple interactions. Introducing a GPU platform enables a substantial increase in the number of elements characterized so that the interaction of multi-legs and ice can be modeled with greater efficiency. For example, level ice modeled with 3-D bonded spherical elements can address the buoyancy, current effects and drag force encountered in harsh environments. Additionally, the parallel bonding approach and de-bonding criteria are used to model level ice freezing and breakage. In this investigation, the global ice loads on a jackup unit's single leg are analyzed to determine the effects of ice thickness, ice strengths and drifting velocities. The estimated ice loads are validated against full-scale data acquired from one application in Bohai Bay. Further, the mechanism of the interaction between the multiple legs and level ice is analyzed using the large-scale GPU-based simulation, the effects of sheltering and jamming are investigated and the ice loads simultaneously acting on the multiple legs are estimated to determine the total shear force and overturning moment.

Offshore drilling has become a key process for obtaining oil. Offshore platforms have many applications, including oil exploration and production, navigation, ship loading and unloading, and bridge and causeway support. However, vibration problems caused by severe environmental loads, such as ice, wave, wind, and seismic loads, threaten the functionality of platform facilities and the comfort of workers. These concerns may result in piping failures, unsatisfactory equipment reliability, and safety concerns. Therefore, the vibration control of offshore platforms is essential for assuring structural safety, equipment functionality, and human comfort. In this study, an optimal multiple tuned mass damper (MTMD) system was proposed to mitigate the excessive vibration of a three-dimensional offshore platform under ice and earthquake loadings. The MTMD system was designed to control the first few dominant coupled modes. The optimal placement and system parameters of the MTMD are determined based on controlled modal properties. Numerical simulation results show that the proposed MTMD system can effectively reduce the displacement and acceleration responses of the offshore platform, thus improving safety and serviceability. Moreover, this study proposes an optimal design procedure for the MTMD system to determine the optimal location, moving direction, and system parameters of each unit of the tuned mass damper.

The sand core of Gulf's bottom founded drilling platform, the Molikpaq, was densified with explosives while drilling on location at Amauliqak F-24 in the Beaufort Sea. A description of how Gulf tackled this unprecedented project is provided. Initially the need for densification is discussed. Selection of the densification methodology and its implementation is then covered in some detail. The test blast program organized to monitor structural responses and the production blasting methodology are explained. The in situ measurements of sand density improvement are summarized and some brief comments on the mechanism of explosive densification are provided. The sand immediately adjacent to the caisson did not meet density targets and was densified with a novel vibrodrainage tool. Finally, time and cost data for densifying sand with both explosives and vibrodrainage on an arctic, offshore platform are provided. This project demonstrates that hydraulic sandfill structures offshore can be densified with explosives successfully, efficiently and cost effectively with limited risks and interruptions to other operations provided the appropriate operating and safety procedures are enforced. INTRODUCTION The Molikpaq drilling platform is presently located at Amauligak F24 in the Beaufort Sea and is currently further delineating the Amauligak reservoir (Fig. 1). The Molikpaq is a monolithic steel drilling platform which is founded on an underwater sand berm (Fig. 2). The core is filled by pumping sand from a trailer hopper dredge via a floating pipeline to the Molikpaq where it is spigotted into place (Fig. 3). The sand in the core is the major load transfer path for carrying the very large horizontal ice loads into the foundations and it is therefore an integral component of the structure's stability. During the initial stages of the Molikpaq' s design in the early 1980' s, it was acknowledged that the structure would be exposed to dynamic, or more precisely monotonic cyclic ice loading. Since the design involved the use of hydraulically placed sand as a load carrying element, the issue of whether densification of the berm and core was necessary existed and remained unresolved. Out of prudence, racks for deploying vibrators beneath the deck were built into the steel structure. However, this method had serious ramifications to the deployment schedule. Subsequently, the geotechnical design work concluded that densification was only necessary in certain circumstances. This conclusion was supported by model tests in a centrifuge as well as the apparent satisfactory performance of many other sandfill islands in the Beaufort. No previous offshore sandfill structure in the Canadian Beaufort Sea has been densified, although contingency plans have been in place on several occasions.

Multi-year (MY) ridge and level ice interactions with sloping and conical structures involve complex ice feature shapes and ice failure mechanisms. The limited available field data makes calibration of associated load models difficult. To account for associated randomness and uncertainty, models may tend to be on the conservative side. New deterministic algorithms were recently developed to calculate loads more accurately for interactions of MY level ice and MY ridges with an upward sloping structure. This paper presents the application of these recently developed formulations in a probabilistic framework using SILS. SILS is a Monte-Carlo type simulator developed by C-CORE following the general procedures outlined in ISO 19906. Ice and metocean input parameters are defined by the user either as a fixed value (e.g. friction coefficients) or a random distribution (e.g. ice drift speed, floe size). The yearly encounter frequency is first estimated for these ice features for the site of interest. The ice loads are then determined for each of simulated interaction event occurring over the model timespan, using the deterministic load formulations. By simulating a large number of years of ice interactions, design ice loads can be determined that correspond to various low annual probability of exceedances. This paper demonstrates how complex loading scenarios, modelled in terms of idealized deterministic models, can be incorporated within a Monte-Carlo framework to provide design level loads. During the model implementation and analysis of results, significant improvements were identified and implemented in the deterministic model, resulting in a more robust model and better design estimates. The results provide valuable insights regarding model inputs and behaviour corresponding to the extreme design ice loads. An example of a full probabilistic analysis is presented in the paper to illustrate the models. Here the probabilistic framework of SILS is used to assess a Base Case scenario and a number of sensitivity cases using different environmental inputs and model parameters.

In this study, a numerical method was developed based on peridynamics to determine the ice loads for a ship navigating in level ice. Convergence analysis of threedimensional ice specimen with tensile and compression loading... | Find, read and cite all the research you need on Tech Science Press

A simulation study on the interaction between sloping marine structure and level ice based on cohesive element model

In December of 1988 a joint venture led by Freeport Sulphur Company discovered a major brimstone deposit of 67,000,000 long tons twenty miles offshore in the Gulf of Mexico. At a production of 2 million tons of sulphur per year this facility will be in operation for the next 30 years. This paper will cover the process of automating the frasch sulphur mine including design and planning, redundancy, reliability, training and configuration. A description of system architecture which allows information for production to be gathered and handled at the facility from process control, production and drilling will be presented. The ability to monitor and control the offshore platform from an onshore facility via satellite communications and the ability to network the process control system with a local area network of host and personal computers will be discussed. INTRODUCTION Main Pass Block 299, is located (Fig. 1) in 210 feet of water, 20 miles east of the mouth of the Mississippi River in the Gulf of Mexico. The production facilities will incorporate the latest technology based upon previous applications, the company's expertise in offshore sulphur mining and on proprietary mining techniques that use seawater in sulphur mining. The offshore production facility will be installed on a series of offshore platforms (Fig. 2) linked together by more than a mile of bridges. The Main Pass facilities are scheduled for completion in late 1991 with sulphur production beginning soon thereafter. One of the greatest tools in assisting operations achieve high safety and efficiency goals is through production automation. Improved productivity as well as improved management of production information can be realized from a modern process control system. Through automation and remote monitoring, operating costs can be reduced and production revenues increased. The strategy was to implement a completely integrated information system - one that gives the association of the process operations data with management and business systems data. AUTOMATION PROCESS Planning There are a great number of factors to consider when developing a plan for plantwide process control and flow of information. The needs and requirements of production planning, engineering, maintenance, material handling, scheduling and overall management are unique when it comes to process control data and business information systems. The first step in the planning of the control system was assembling a team of people from the various areas listed above. The company had to make a decision to make available the best that the company has to offer in the areas of production, maintenance and engineering to be a part of the team. Because of their other responsibilities in construction of this facility as well as running existing facilities it is almost impossible for them to spend a majority of their time on process automation alone. Once a team was established then the next step was to set the criteria for controlling the process and the handling of production data.

BP has been operating in the Caspian Sea and associated area (AGT Region - Azerbaijan, Georgia and Turkey) since the early 1990's and today the area is one of the world's leading hydrocarbon provinces. The assets consist of 7 offshore platforms, one of the world's largest terminals and export pipelines. The topic of this paper is a description of a practical implementation of an assessment procedure for determining optimum inspection frequencies (endorsement interval) for pressure relief devices protecting pressure system equipment. We describe the development process, the resulting solution and work processes, the challenges related to the data requirements and dependency of the maintenance and inspection organizations to record and collate such data. Within the AGT Region there are in excess of 5,800 pressure relief devices. Pressure relief devices provide a key layer of protection for the process safety of oil and gas fields and installations and need to operate on demand as and when required. All need to be inspected, tested and recertified on a regular basis. The objective of the exercise from the outset was to increase the process safety protection and reliability on the installations. Flow charts were developed to ensure the methodology was clear, simple, repeatable and auditable. This methodology was then combined with knowledge and expertise on the failure mechanisms of safety devices and the consequences of an uncontrolled release to atmosphere to determine an optimal endorsement interval and verify that the device was functioning properly thereby preventing the over-pressuring (or under pressuring) of equipment during abnormal operating or emergency conditions or leakage past the seat during service. The output from the work showed that around 70% of the pressure relief devices could have their maintenance and inspection intervals increased, by up to 6 years. The work was initiated when the oil price was in excess of 100US$ per barrel and on BP facilities that are top of the league in terms of production efficiency (greater than 90%). The primary objective was to improve the safety, reliability and integrity of the installations, however the resulting benefits of performing the assessments aligned to the ability to increase inspection intervals are to significantly reduce maintenance costs, reduce offshore and onshore interventions and increase availability and production efficiency. The team also reviewed and enhanced the management procedure for the testing, repair and recertification of pressure relief devices, to provide additional guidance to the maintenance teams in the areas of data collection and recording and witnessing pressure relief device testing and re-certification.. To the authors knowledge this is the first practical implementation of the assessment procedure that embraces the total combination of asset integrity information and work process data sources within a whole oil and gas producing region.

Multipath, reverberation, and natural and man made noise limit the data rate and reliability of underwater acoustic command and telemetry links. This paper describes signal coding, gating, and receiver design techniques used in the RATAC(R) acoustic command and control system. Probability relationships for correct and error commands are derived and performance predictions made as a function of range. Test data on an offshore drilling platform is compared to theoretical performance predictions. 1.0 INTRODUCTION Acoustic telemetry techniques for control of underwater devices are limited by the constraints of the acoustic medium and its boundaries, and the sources of noise which are present in the underwater environment. Reliable command operation of these devices is a stringent requirement due to their inaccessibility and the slow communication data rates. Errors and undesired commands must be avoided in all types of noise and interference. This paper will discuss the signal processing and coding techniques, and the predicted and tested performance of the Raytheon RATAC (R) * acoustic command and control system. The system provides multichannel capability, and is designed to minimize the probability of a false command caused by natural or man made noise, or propagation effects. This is accomplished through the use of frequency diversity, time coding, and receiver gating. Test results at a drilling platform installation are included. 2.0 THE UNDERWATER ACOUSTIC ENVIRONMENT The background noise environment consists of several natural and man made noise sources. The most important natural noise sources are the usual sea state noise and the noise due to raindrops striking the surface.1 These spectra are shown in Figure 1. Biological noise sources are primarily concentrated at low frequencies, with the exception of snapping shrimp, which produces a noise level about equal to the rain noise spectrum.2 Interference due to porpoise and whale calls, which may appear similar to tones or frequency slides, is minimized by signal frequency coding and time gating techniques. Man made noises are generally localized, and generate most of their energy in the low frequency regions of the spectrum. The noise spectra produced by normal operation on a drilling platform have been chosen as a worst case. Two spectra are shown in Figure 1 for drilling platform noise.3 & 4 The first is the peak values of measured noise level from the CUSS I drilling barge; and the second is the noise level measured at a distance of 70 yards from a fixed leg platform, and referred to a standard reference distance of one yard. Spherical spreading was assumed as a worst case. The difference in measured levels is due to the presentation of peak values in the first case for the noise spectra, and the different platform noise characteristics. These curves include the maximum expected noise levels, with the exception of isolated events such as explosive pipe cutting. The noise spectrum consists of many line components as well as a broadband background. The signal decoding technique for a telemetry system must there for be able to discriminate against line frequency components as well as the more common white Gaussian noise background generally assumed for computational convenience.

Modem ULS instruments provide year-long continuous measurements of sea ice drafts with an unprecedented time resolution of 1-2 seconds and a horizontal resolution of approximately 1 m. In this paper we analyze multi-year moored ULS measurements of sea ice in the Chukchi and Beaufort Seas and off Northeast Greenland. Recently, the massive ice feature (MIF) parameter has been developed to provide a robust, geometrical characterization of all potentially hazardous marine ice features within a ULS ice draft data set. An MIF episode is the set of consecutive ice draft values which exceed a specific minimum ice draft (e.g. 1.2 or 2.0 m) having total cross-sectional area above a specified value (e.g. 250 m2). A database of all MIF episodes is prepared including area, distance and ice drafts (mean and maximum). Previous research has shown the MIF database from year-long mooring measurements to be a complete and robust characterization of potentially hazardous features. In this paper, we apply algorithms that detect different types of sea ice features: large singular ice keels, hummocky ice, thick brash ice, old or multi-year ice and marine glacial ice (icebergs and ice islands). These ice types are associated with individual MIF episodes so that each episode can be associated with one or more ice type. There are large variations in the numbers of MIF episodes among regions, with NE Greenland having the most frequent occurrences of MIFs. For NE Greenland approximately 40% of MIF episodes can be identified as large keels and less than 15% as hummocky ice episodes; however, the hummocky ice episodes typically have considerably larger crosssectional areas than large keels. There are fewer occurrences of multi-year ice and very rare occurrences of marine glacial ice. The MIF analysis results provide improved quantitative values for pressure loading of sea ice on offshore platforms and ships, as well as understandings about the nature of sea ice deformation and age characteristics.

Developments in flare systems for the emergency de-pressurisation of oil production trains on offshore platforms in the North Sea are reviewed in terms of safety, efficiency, cost, installation and material usage. The most commonly used systems are enumerated and the fundamental requirements re-stated. Appraisal is made and notional costs given of each type cited. API guide RP521 rules for the calculation of radiation and temperature levels are examined and the extrapolations to them required for use on North Sea platforms stated. Structural prob1ems in the design of lightweight structures subject to ice and high wind loadings are examined with regard todynamic analysis of individual members.consideration of wake induced forces and shielding.the derivation of wind force spectrum from considerations of wind structures for inclusion in a dynamic analysis of complete structuresselection of heat resistant materials in locations near the heat source INTRODUCTION The exploitation of oil fields in the North Sea has led to situations which the generally adequate design guidance given in the API guide for pressure relief and de-pressuring systems (RP521) does not cover specifically. Its intent has therefore been extrapolated in various ways and the object of this paper is to review and to make a personal appraisal of what has been done to date with regard to one aspect, namely the positioning of burners and the concomitant structure which supports the gas lines to the burners. The main special circumstances in the North Sea which have influenced facilities design are as follows:In deep, storm prone, waters economics dictated that complete facilities be provided on single platforms. Where pipelines to shore were not possible these facilities had to include storage in addition to drilling, primary separation and production.On single platforms the separation of hazardous areas from accommodation and communication areas could no longer be achieved by separate platforms inter-connected with bridges but had to be by fire barriers dividing a single platform. This necessitated that either the gases to be burnt were taken directly from the process area and flared from near that hazardous area on the platform or the gases were conducted away by sub-sea line to a stack mounted on a secondary p1atform or swivelling buoy remote from the main structure. For shallow, calm water the remote stack solution combines safety with economy. For deep, rough water maintenance problems concerned with purging accumulations of condensate in the sub-sea line and igniters and pilots sharply reduce safety standards, while the placing of the lines and remote stacks in depths of water up to 150 metres multiplies the minimum cost by a factor of at least 8. A further complicating factor is that, due to the present climate of energy conservation, large volumes of gas are only flared in an emergency de-pressurisation or during commissioning of plant although the pressure relief system must assuredly be available for an emergency, it is otherwise lightly used. A system in frequent heavy use must be kept in efficient working order, one lightly used is liable to receive less attention.

Mars is an offshore drilling and production platform operating in the deepwaterregion of the Mississippi Canyon area in the Gulf of Mexico. It startedproduction in 1996 with a design basis of 140,000 BOPD. In 2003 at the start ofthe work reported here, Mars was producing an average of 200,000 barrels of oilper day. While the platform had undergone a number of expansions, many processunits, including the Bulk Oil Treater were operating above the design capacity. Due to the high throughput and therefore short residence times, the platformwas experiencing oil dehydration problems, and a high rate of demulsifier wasrequired to meet the oil discharge dehydration target of 1.0 % BS&W. The original Mars electrostatic treater was a conventional design involving aserpentine perforated pipe distributor, steel electrostatic rods, conventionalAC electrostatic treating technology and a perforated pipe collection header. During the hurricane Katrina shutdown (late 2005/early 2006), the Mars Bulk OilTreater was upgraded to composite grids, Dual Frequency® AC/DC electrostatictreating technology and a Hi-FloTM pipe / deflector spreader. After theupgrade, a significant savings in demulsifier cost was realized. This paperdiscusses how the new electrostatic treating technology was used to reducetreating chemical cost and improve throughput. Additionally, comparison ofdifferent crude dehydration technologies is discussed. Introduction When a field reaches its maximum production rates, mechanical separationcapacity is often exceeded. For deepwater platforms, separation residence timeis typically short due to the high cost of space and weight. Topsidesseparation problems can be costly, particularly when production must bedeferred to meet oil or water quality specifications (BS&W and oil in waterconcentration). The work reported here was carried out in 2003 through early 2006. It wascarried out in two phases. In 2003 and early 2004, the platform was operatingat historically high production rates. Oil production averaged 200,000 BPD. Dehydration problems were addressed by adding more heat, improving the chemicalapplication, and improving the operating procedures. In addition, the option toupgrade the Bulk Oil Treater vessel internals was evaluated during this timeperiod. This was the first phase of the work during which the platform wasoperating at high production rates.