bluuebunny/crossref_metadata_2025 huggingface dataset:
High-Integrity Protection Systems (HIPS): Methods and Tools for Efficient Safety Integrity Levels Analysis and Calculations
Authors: Signoret Jean Pierre
Published: October 2008

This paper shows how to deal properly with "Safety Integrity Levels" (SIL) as per IEC 61508 [1] and 61511 [2] for "High Integrity Protection Systems" (HIPS) which are more and more extensively used in oil industry to replace traditional protection systems. If IEC 61508/511 are rather efficient from an organizational point of view, some difficulties unfortunately exist at definition and calculation levels. The formulae proposed in part 6 of IEC 61508 are, for example, not really tractable for actual industrial systems. This paper describes the probabilistic methods and tools that we have developed in our company to overcome the above difficulties. Three main conventional methods are investigated: "Fault Trees" which, when properly handled, are very efficient for low demand topside HIPS, markovian approach which is interesting but tractable only for very small systems and Monte Carlo simulation on behavioural models (Petri Nets or AltaRica Data Flow formal language) which is efficient in any cases. Results are given on simple examples in order to show the principles of the various approaches. It is interesting to notice that using those approaches is simpler than what is proposed in the standards. Therefore, until the publication of an updated version improving IEC 61508 part 6, it seems better to replace it by sound conventional methods and tools adapted to SIL calculations for production systems. We have began to disseminate this approaches toward our contractors.

Introduction

In the oil industry, the traditional protection systems0 defined in API 14C are more and more often replaced by safety0 instrumented systems: the so-called HIPS (High Integrity Protection Systems). Therefore, according to IEC 61508 and IEC 61511 Standards, their SILs (Safety Integrity Levels) shall be calculated

Unfortunately, when using above standards some difficulties arises [3, 4]. They often remain ignored by those who perform SIL studies and the main ones are the next:insufficient failure taxonomy and definitions,tests and maintenance procedures handling,introduction of the Safe failure Fraction (SFF) which is not a relevant concept,probability of Failure on Demand (PFD) and

Probability of Failure per Hour (PFH) Calculations. After presenting briefly the 3 first problems, the 4th one will be detailed more in depth to show what we have done to cope with the various SIL assessment problems encountered in the oil industry:topside HIPS easily tested and maintained,subsea HIPS difficult to test and maintain,preventive HIPS.

According to the standards topside and subsea HIPS are so-called "low demand mode" safety instrumented systems (SIS) while preventive HIPS are so-called "continuous" mode SIS. This paper is mainly focused on methods and tools devoted to low demand mode HIPS.
Sonic Cover Survey of an Offshore Pipeline
Authors: Peebles E. Earl , Guerry T.L.
Published: October 2008

All pipelines are subject to erosion as well as the removal of' protective earth covering due to the elements of nature. If permitted to continue to its ultimate conclusion, that of a long unsupported pipe span, failure of the pipe is almost sure to result. While it is fairly easy to patrol land pipelines to guard against excessive erosion, a measure specified by the Federal Minimum Standards, patrol of submarine pipelines have, for the most part, been unfeasible in the past. Attempts by divers and miniature submarines have been prohibitively expensive, and in many cases the findings have been inconclusive.

The advent of more sophisticated underwater electronic and sonic equipment suggested the possibility of an almost totally electronic survey, thereby increasing reliability and substantially decreasing costs. This paper presents the equipment and techniques utilized in such an offshore cover survey of a 16-in. submarine pipeline located off the Galveston coast. It begins with a detailed description of the equipment used, such as the differential proton precession magnetometer, recording fathometer, low frequency acoustic subbottom profiler and the ultra-sensitive dual channel side scan' sonar. All of these are readily available through most offshore survey contractors. Methods and techniques are developed enabling any offshore pipeline operator to conduct such a survey.

The actual survey, conducted during the summer of 1972, substantiates the belief that such surveys are both practical and economically feasible. Important side benefits of such a survey arethe precise location of the pipeline in the event that a leak must be located and a repair made at a later datethe detection of the presence of debris on or near the pipeline andthe assurance that the pipeline has not been moved an appreciable distance by a storm.

INTRODUCTION

The purpose of this project was to perform a detailed investigation and determine the existence and extent of any bridged sections of the approximately 36.4 miles of ballasted 16-in. pipeline owned by Black Marlin Pipeline Co., Inc. Located offshore, the Black Marlin pipeline extends from off the Texas coastline in High Island Block 136 to a point on the Bolivar Peninsula in High Island Block 194. Methods for the performance of this underwater location and cover survey utilized the latest and most modern equipment and techniques for obtaining the field data and for purposes of preparing the final report.

In order to establish the scope of work, a list of the information required with regard to the present status of the pipeline was set out. The desired information washorizontal location of the pipeline,vertical location of the pipeline,existence and extent of a bridged sections of the pipeline andlocation of any large metallic objects, exposed wrecks, sand waves, or other obstructions appearing in the immediate area of the pipeline right-of-way.
Subsea Pumping Systems: Intervention Prediction and Condition Monitoring Techniques
Authors: Eriksson Klas , Falk Kristin , Melboe Hallgeir , Mjaavatten Erlend
Published: October 2008

For subsea pumps, regular maintenance is required (in the order of every 5 years or so). Being able to plan this intervention to be "just in time" will reduce downtime, and optimize production. Such techniques have been applied to topside systems for a long time, and are now being extended to subsea pump systems. A data monitoring system with algorithms for monitoring certain Key Performance Indicators for a pumping system has been developed and applied, and is used to determine "time to service". Two subsea pumping systems (for King and Lyell fields) are used as real examples, with results from system operation (Lyell) and integration testing (King) for same.

Introduction

Subsea pumps need regular maintenance due to general wear. The service interval depends on the operating conditions of the pump. Servicing a pump basically involves replacing it with a spare pump. Such intervention is preferably scheduled in order to minimize the downtime. An unscheduled intervention can easily give a downtime of one week and up to 8 weeks in winter in case of rough weather in certain areas, while a planned intervention can be done in 24 hours. As an example, a pump providing a production increase of 5 000 bpd, and with an oil prize of 50USD, the lost production will be at least 1.7 MUSD with a 1 week unplanned shut down. The lost production can be as much as 14 MUSD in case of having the pump installed in areas where a rough winter weather can make it impossible to change the pump (for an 8 week shutdown).

For a planned 24 hour intervention, the corresponding production loss would be in the order of 0.25 MUSD. If we can avoid a single unplanned shutdown in good weather, we can thus save appr 1.5 MUSD.

If we can avoid a single unplanned shutdown in areas where bad weather is critical, we may save 14 MUSD. The intervention can be done based on several schemes, g.:"Run until it breaks". This gives 1-8 weeks downtime every time"Change every 4 years". This is based on worst case calculations"Change just in time". This is based on some knowledge of condition

Compared with how a car is serviced, option a) is seldom used. Option b) (scheduled on time / mileage) is the most common method. Option c) is used on more advanced cars, which keep track on how hard they are driven, and give advance warning on how many miles are left until service is required.

What we are discussing is thus basically what advanced car manufacturers have done for many years, i.e. scheduling maintenance based upon how hard the system is operated. Also, in the same way as for cars, regular maintenance can-not guarantee against unscheduled breakdowns, but it will reduce the risk for such. In order for such a system to give any real benefit, it must be able to give sufficient advance warning that a planned intervention can be made instead of an unscheduled one.
Electronic Survey Helps Assure Integrity of Offshore Pipelines
Authors: Rogers W.M. , Duckworth H.N.
Published: October 2008

On-land practices of excavating and sampling for detection and evaluation of corrosion in pipelines are, at best, inadequate. Such a practice regarding offshore pipelines would be very impractical for many reasons. However the need and concern for corrosion evaluation of pipelines in that area are just as great if not more so than land lines.

A more detailed method developed over the past few years is now in use for evaluating corrosion and mechanical damage in offshore pipelines. Electronic surveys have been performed on several major offshore lines. Data provided by the surveys enables the operator to locate, evaluate, and through subsequent surveys, monitor corrosion and other conditions.

Base line surveys were run on two lines from platforms in the Santa Barbara Channel to shore immediately after construction was completed. Subsequent surveys have been performed to monitor and assure the integrity of the pipelines. Other surveys have been made on offshore lines in or near metropolitan areas when leaks could seriously affect public opinion.

Electronic surveys may be performed on offshore lines under most conditions and without interruption of pipeline operations.

TEXT

Almost anything that would adversely effect the integrity of a pipeline has been of concern to the operators of those pipelines. In many cases, pipeline companies have taken elaborate steps to protect the lines from damage or deterioration. Pipe surfaces are frequently coated with a corrosion barrier, cathodic protection systems are installed to counteract corrosion processes, and other devices are used to further protect the pipe. In spite of that protection and attempts to safeguard systems, pipelines become damaged and/or otherwise deteriorate in some manner.

It is believed that most deterioration occurs in the form of corrosion. Even with the application of corrosion prevention coatings or devices, some corrosion degradation frequently develops. Pipeline corrosion control personnel work diligently to monitor conditions developing in their pipeline and upgrade the protective installations. In addition, pipe surfaces are frequently examined when and where possible. On-land procedures of excavating sections of buried pipeline have been an extensive practice for many years in order to observe pipe surfaces and evaluate corrosion conditions. For the industry, this practice requires the use of many men at the expense of many man hours and at best, the practice can only expose a limited portion of a major line. Since large sections of a line may go unexamined by this method for a time, extensive damage could go undetected and result in a line failure.

Such a practice on offshore pipelines is basically impractical because of the water environment and other factors.
Ice Breaking Drilling Ship for Offshore Exploratory Drilling In the Arctic
Authors: Jones Klemme M. , Schaff James C.
Published: October 2008

INTRODUCTION &ACKNOWLEDGEMENT

About two years ago it became apparent that the offshore oil potential in the Beaufort Sea and Canadian Islands Arctic areas was sufficient to give serious consideration to a method of practically and economically providing a system capable of performing the needed exploratory drilling service. The practical approach was to utilize proven drilling techniques, systems and equipment to the maximum degree; but to synthesize these to an environment not previously considered in their design; and the imagination to accept opposing precepts from the preceeding and conceive a viable, practical compromise. The economics dictate that the results must reasonably be capable of profitable application.

Global Marine's long-stated preference for ship-shaped units for exploratory drilling and the existing technology of breaking navigable ice channels with ships afforded an immediately marriageable pair of disciplines which would yield fruitful results: The only total unknown was how to maintain drilling station in a slowly moving ice sheet.

Global Marine Engineering Company has been the chosen instrument to provide the synthesis, application and imagination leading to the desired results.

No single individual (or organization, for that matter) can claim parent to the total developing design presented herein. It is the result of many inputs, many thoughts, much joint effort. And it is a developing design. Manuscript time schedules being what they were for papers for this conference, much of the illustrative material and tabular data must be considered as developmental, a substantial amount of which are already obsolete in their detail and qualitative values.

The authors wish to acknowledge the contributions of time, effort and talent made by members of their staff, both professional and clerical. Further acknowledgements are made to the ideas, direction and support provided by Global Marine, Inc. - especially Russel B. Thornburg; Arctic Engineers and Constructors Ed Anders in particular; Wartsila Ice Model Basin's remarkable staff (Dr. Endquist, B. Johanssen, O. Makinen and K. Airaksinen specifically); and Prof. Grim and Dr. Waas of the Hamburg Ice Model Basin. Without them and many others we might still be floundering in a sea of uncertainties.

DESIGN CONSIDERATIONS AND PARAMETERS

The marriage of a drill ship with an icebreaker provided the basis of the design considerations (see Figure 1). Throughout the design of the vessel safety has been the overriding criteria. Safety not only for the personnel vessel and equipment but, also safety in terms of environmental protection. The design evolved around considerations of the environmental parameters such as climatic conditions and environmental impact; crew equipment and vessel safety; regulatory parameters; and of course ice-breaking and operational requirements.
Two New Operational Units for Steel Wire Line Work on Subsea Wellheads
Authors: Issarte Jean-Pierre , Masoriheimer R.A. , Vaissade Louis
Published: October 2008

Two new units have been designed for adapting the steel wire line method, in universal use on land, to suit subsea wellheads.

The subsea lubricator method makes use of a swell compensating unit installed on board a surface support and enables wire line operations to be performed from a standard vessel and using a standard wire line winch.

The subsea winch is a unit which is lowered into the water and connected to the wellhead. It is completely remote-controlled from the surface by means of a multi-conductor electric cable.

These two units have been successfully tested several times on both experimental and producing subsea wells. They are now operational.

INTRODUCTION

There are still comparatively few oil wells in the world which are completed with subsea wellheads, no more than about a hundred in all. It is, however, very likely that this number will increase quite rapidly over the next few years with the development of subsea fields. The various systems being tested at present in several countries for the equipment and maintenance of such producing wells is evidence of this trend.

In all these systems there is generally some method of working inside the wells to carry out operations which are simple but necessary if the wells are to be operated in a rational manner, such as bottom hole pressure measurement, tubing scraping, handling bottom hole tools, etc. The methods proposed are sometimes rather cumbersome and some of them are not, in our opinion, satisfactory from the point of view of operating safety.

We have therefore studied a way of adapting for subsea operations the wire line or slick line technique, universally used on land. We would recall that this technique, which now has specialists with long experience, involves introducing equipment into the well through a lubricator and then running it to the bottom of the well at the end of a steel wire line, unwound from a winch. The seal is made around the line by means of a stuffing box.

OPERATIONS ON PRODUCING WELLS

In wells on land, as in the case of offshore wells operated from fixed platforms, the wire line technique is widely used. In wells with subsea trees, a new operating method has been developed and tested by various companies over the last few years.

This method abandons the use of slick line and makes use of a fluid to pump the tool string in the tubing. This "pump down'tools" technique probably has a great future ahead and the fact that almost all the subsea systems being tested or studied at the present time make use of this technique, demonstrates the success anticipated.
Maintaining Late-Life Production From Long Offset Subsea Gas Wells
Authors: Becnel Miles , Steib Don , Wegener Stephen , Linder Jacobs , Beg Najam
Published: October 2008

The ability to maintain late-life production from long offset sub sea gas wells is very much dependent on the well stream's ability to reduce flow line pressure by effectively sweeping liquids from the flow line. This paper reviews the application and results of utilizing a gas ejector on long offset sub sea gas wells to enhance recovery. Although this document focuses on a sub sea application of this technology, gas ejectors can also be utilized on any low pressure well. The use of this device should be seriously considered when applicable. Its interchangeable internals allows the same device to be utilized through a wide range of productions and pressure regimes and can be relocated as needed.

Post-installation data has shown that the installation of the gas ejector has performed as per the stated design and is a technically feasible and cost effective means to recover additional reserves from low pressure wells. It is particularly attractive where an existing high pressure gas source is available.

The authors consider this the first application of this type in the Gulf of Mexico and since installation have received inquiries about potential applications for other Gulf of Mexico assets.

Introduction

The Gemini field is located in Mississippi Canyon Block 292 in 3400 feet of water. See Figure 1. The field was discovered in 1995 and production commenced in 1999. The original development consisted of three sub sea wells tied back to the Viosca Knoll host facility via two 27 mile long flow lines. Since first production, reservoir pressure and production rates have decreased to the point where the reservoir's natural ability to adequately sweep the flow line of liquids no longer exists. As a result it was predicted that the field would cease production unless a method to lower flow line pressure and reestablish a means to sweep the flow lines was developed. Several options were considered and a gas ejector was selected as the preferred alternative. This paper describes preinstallation operations, other options considered and design considerations specific to the Gemini facilities. In addition pre- and post-installation production and pressure history are presented.

Pre-installation Operations

Prior to the installation of the gas ejector, the Gemini wells flowed through a sub sea manifold where they could be routed into either of two 27 mile long 12" flow lines. Originally, production volumes required the utilization of both flow lines, but, eventually the declining production created the need to flow both wells into the same line. This continued until the pressure and corresponding velocity in the single line became inadequate to effectively sweep the liquids from the line. The resulting liquid hold-up in the long line caused excessive pressure drop and high manifold pressure, causing the wells to load-up with fluid.
From P-34 to P-50: FPSO Evolution
Authors: Henriques C.C.D. , Brandão F.E.N.
Published: October 2008

PETROBRAS started to use ship-shaped processing and storage vessels (FPSOs) for offshore production in 1979, through the installation of a process plant over the deck of the P.P. Moraes oil tanker (later renamed to P-34). In April 2006, the P-50, PETROBRAS' latest and most complex FPSO, ever, started production in Albacora Leste Field.

In these last 25 years, the concept and design of our FPSOs suffered a large transformation, from the simplified production plants for up to 50,000 bpd used in the late 70s, through the large FPSOs converted in the mid-90s, up to the concept adopted in P-50 project.

In this project, the concepts of modularization and selfcontained equipment packages allied to the life enhancement strategies adopted to guarantee an operational life in excess of 25 years, lead to a design that can be considered "top-of-class" for converted FPSOs.

In this paper it will described how the design of PETROBRAS' FPSOs evolved highlighting the modifications made in the design of P-50 main systems.

Introduction

PETROBRAS has a long history of using ship-shaped production units in its offshore projects starting in the end of the 80's. Table 1 shows the list of our FPSOs in design, construction or operation and the FPSOs that were demobilized. At present, we have 11 FPSO/FSOs in operation, and we can divide the history of those Units into 3 phases, as can be graphically seen in figure 1 that shows the number of FPSO/FSOs that entered production in each year, since 1987:Phase I: In this period, from 1979 up to the beginning of the 90s, FPSOs were used mainly as Early Production Systems;Phase II: This period, up to the end of 90s, comprises the boom of FPSO construction and installation in the Campos Basin;Phase III: In this phase, the use of FPSOs was consolidated and a second generation of units was built, taking into account all the experience gathered in the first wave of FPSOs from the second phase.

Nowadays we can see that a new FPSO Phase is beginning, with the development of P-57 project, our first newbuilt designed FPSO.

Evolution of FPSO Concept in Brazil

Phase I:

In the Campos Basin, the first CALM buoy was installed in the Enchova Field, in 1978 in order to allow the mooring of an oil tanker to receive the production from a drilling rig in a pilot production system.

The first mono-hull floating production unit to operate in the Campos Basin (and one of the first FPSOs in the world) was the former tanker P.P. Moraes. This 33,000 dwt tanker was built in 1959, and, in 1975 it was jumboized to 54,000 dwt. Then, in 1979, a 60,000 bpd process plant was installed in P.P. Moraes to allow it to operate in the Garoupa field, moored by a tower-yoke system as can be seen in figure 2. In 1980, the tower failed from fatigue at the ballast tank, and a CALM buoy was then installed in the field, to moor the P.P. Moraes FPSO through a soft yoke (figure 3).
Sand Transport Modeling in Multiphase Pipelines
Authors: Danielson Thomas J.
Published: October 2008

Prediction of the critical flow rate that will result in sand bed formation in multiphase flow is a critical aspect of multiphase production. Many correlations have been developed for solids transportation in multiphase flow; however, all of them treat the multiphase flow in an ad hoc way that does not respect the complexity of the phenomenon. Further, many approaches rely on correlations that have been developed for much higher solids loading than would occur in oil and gas production. In this paper, first a correlation for liquid-solid transport is developed, based on data taken in the SINTEF STRONG JIP. A good fit to both sand bed height and measured pressure drop is obtained. A critical aspect of the model is the assumption that there is a critical slip velocity between the sand and liquid which remains relatively constant over a wide range of flow velocities. Second, the particle diameter is used to augment the surface roughness. A critical velocity correlation is developed, based on solid and fluid properties, and pipe diameter. An essential feature of the model is that the critical slip between the liquid and solid phases is unaffected by the presence of gas. Good fit to the data is obtained. A sand model is developed using OLGA2000 which does a good job in fitting sand hold-up against the experimental data. Such a model can be used to predict sand bed formation potential in field lines.

Introduction

Sand is often produced out of the reservoir in both onshore and offshore production systems, particularly in reservoirs that have a low formation strength. Sand production may be continuous, or sudden - as when a gravel pack fails. In the case that no downhole sand control is done, or that a sandcontainment strategy fails, a sand-management strategy must be employed, with operations designed to tolerate a certain amount of sand production. Deposition of sand beds poses several risks, including increased frictional pressure losses, increased risk of corrosion due to microbial attack under the sand bed, and increased risk of equipment failure due to sand. Sand transport in near-horizontal pipelines has four main regimes, depending on the fluid flow rate. Below a critical velocity, sand will drop out of the carrier fluid and form a stable, stationary sand bed. As the sand bed builds over time, the fluid above the bed is forced into a smaller cross-sectional area, causing the fluid velocity to increase. When the velocity reaches a critical value, sand is transported in a thin layer along the top of the sand bed. A steady-state is reached, such that the sand eroded from the top of the bed is replaced by new sand production from upstream. At higher velocities, the sand bed begins to break up into a series of slow-moving dunes, with sand particles transported from the upstream to the downstream side of the dune. As the flow velocity increases still further, the dunes break up entirely, and the sand forms a moving bed along the bottom of the pipe.
Physical Properties of Mass Transport Complexes in the Ursa Region, Northern Gulf of Mexico (IODP Expedition 308) Determined From Log, Core, and Seismic Data
Authors: Dugan B. , Flemings P. B. , Urgeles R. , Sawyer D. , Iturrino G. J. , Moore J. C. , Schneider J.
Published: October 2008

Mass transport complexes (MTCs) in the Ursa region (northern Gulf of Mexico) are identified by their low seismic reflectivity, increased resistivity, increased bulk density, high shear strength, and decreased porosity. We integrate seismic, logging while drilling (LWD), and core data to identify MTCs and to characterize their physical properties. The seismic signature of MTCs includes high amplitude reflections at their bases and low amplitude, and often non-continuous, internal reflections. Resistivity increases in MTCs (up to 10%) creating a contrast with overlying and underlying, nondeformed sediments. Increased resistivity correlates with increased bulk density and visual observations of increased deformation. We interpret that increased density results from consolidation associated with shear deformation. This creates different resistivity-density relations for MTCs and non-failed sediments. Undrained shear strength measured on cores increases by as much as 20% in MTCs where resistivity and density are high. Consolidation during shear deformation also decreased permeability of mudstones in this basin. The combination of rapid deposition and low permeability may have contributed to shallow overpressure in the Ursa region.

Introduction

Mass transport complexes (MTCs) are sedimentary bodies that have experienced downslope migration and various degrees of internal deformation. Previous studies have evaluated the geometry and stratigraphy of MTCs using 2D and 3D geophysical data [e.g., 1,2]. Other studies have related the distribution and size of MTCs to natural disasters associated with submarine slope failures. In few instances natural disasters have been observed as direct result of slope failures. The 1929 Grand Banks tsunami was caused by an earthquake-induced submarine landslide that damaged oceanic infrastructure and caused deaths onshore [3]. In 1998, an earthquake-triggered MTC produced a tsunami that killed >2000 people on Papua New Guinea [4]. In addition to human fatalities, submarine landslides have also caused direct damage to coastal facilities (e.g., the Nice airport, France [5], and Finneidfjord, Norway [6]). Detailed physical and sedimentological characterizations of MTCs have allowed the oil industry to better identify hydrocarbon reservoirs and seals [e.g., 7] and has been used to evaluate physical properties that may impact shallow infrastructure [8].
Optimization of Tension Level and Stinger Length for Offshore Pipe line Installation
Authors: Daley Gregory C.
Published: October 2008

Offshore pipelines have been installed for a period of' some 10 to 20 years using a variety of methods. This paper presents a new analysis method for the optimization of certain operation parameters in laying continuous pipe under tension from a barge. This method of optimization is now being used by one of the major offshore contractors. The solution is given by matching geometrical parameters through graphical overlays of network charts obtained by a computerized finite element iterative solution the solution is based on the requirement that the tension level be optimized with respect to either the minimum stinger length or the maximum average radius of curvature of the stinger.

INTRODUCTION

The problem that this paper deals with is that of laying oil and gas-pipeline offshore (Fig. 1). The problem consists of, how one might place the pipeline on the sea floor without kinking or buckling the pipe. This is done by ensuring that the stress is always below some allowable stress; for example, 80 percent of yield stress. The stress is proportional to the bending moment. Typically, the stress induced by the bending moments is an order of magnitude to two orders of magnitude larger than the stress induced by either the tension level at which the pipe is being pulled or the hydrostatic pressure of the sea water.

In order to relieve the bending moment in the sag bend (and thereby reduce the stress) the pipe is pulled by a tensioning device, typically capable of producing a horizontal tension level, H, ranging from 0 to 120,000 lb.

As the pipe comes off the barge, it rests in a flexible buoyant support called the stinger. The stinger of length, S1, is partitioned off into a series of tanks and each tank can be filled with either water or air. The stinger, therefore, has some average radius of curvature, p. other methods of varying stinger curvature exist such as varying support roller heights with respect to the stinger.

The other operational parameters are the entrance angle, a, of the pipe coming into water off the barge; the rigidity of the pipeline, EI; the submerged weight per unit length, q, of the pipe j' and the depth of the water, WD. The contractor has control over the tension, H; the stinger radius of curvature, p; and until the stinger has, been built, the length, S1, of the stinger.

It should be pointed out that, prior to this system, the analysis was accomplished'by fixing all seven of the variables, solving for the moment as a function of arc length using a complex computer program, and checking each moment. If one of the moments happened to be greater than the allowable, then one or two or three of the parameters were adjusted, based on "engineering intuition".
In-Situ Pore Pressure at IODP Site U1324, Ursa Basin, Gulf of Mexico
Authors: Long H. , Flemings P.B. , Germaine J. , Dugan B. , Sawyer D.
Published: October 2008

We measured pore pressures with two pore pressure penetrometers at IODP Site U1324 in Pleistocene sediments of the Ursa Basin, Gulf of Mexico, directly offshore from the Mississippi Delta. Between the seafloor and 300 meters below the seafloor (mbsf), overpressures reach 80% of the hydrostatic effective stress (?=0.8=(u0-uh)/(?v-uh) In this interval, only low permeability mudstones are present. Beneath 300 mbsf, ?* is approximately 0.2 and the sediments are composed of interbedded mudstone, siltstone, and very fine sandstone. We interpret that the lower relative pressures beneath 300 mbsf are caused by the higher permeability of these sediments. Penetrometer deployments ranged from 30 minutes to 90 minutes, which was not enough time for the measured pressure to dissipate to the in-situ pressure. To estimate the in-situ pressure, we used two inverse time extrapolation techniques: 1/?t, and1/t. We use a theoretical soil model to show that the 1/?textrapolation provides a desirable accuracy in much shorter amount of time than the 1/t extrapolation.

Introduction

Overpressures, pore pressures in excess of hydrostatic pressure, have been observed in sedimentary basins around the world 1. Knowledge of the distribution of overpressure is critical to explore, drill, and produce hydrocarbons 2, 3. Overpressures drive pore water flow 4, impact large-scale structural development 5, and affect the state of stress 6.

In young, cool, sedimentary basins, overpressures are generated in low permeability mudstones due to their inability to drain as they are loaded by sedimentation or deformation. Although the pressure is generated within the mudstone, it is most often measured in permeable formations adjacent to the mudstone 3. Recently, the petroleum industry has extended geotechnical techniques to measure pore pressure within mudstones through the use of pore pressure penetrometers in the borehole to depths of many hundred of meters 7–9. This exciting technique provides direct measurements of pore pressure in low permeability rocks and in some locations it has documented very high pore pressures immediately beneath the seafloor 7.

When the penetrometer is pushed into the formation below the bottom of the hole (BOH), a pressure disturbance is created. The time that it takes to disipate this pressure depends on the probe diameter and the hydraulic diffusivity of the sediment. In ocean drilling, the time available for downhole tool measurements is expensive and limited. In this environment, in-situ properties must be interpreted from partial dissipation records. If detailed soil properties are available, the in-situ pressure and diffusivity of the sediment can be inferred from modeling of soil behavior for different penetrometer geometries 10–14. However, in many cases soil properties are not available, or there are insufficient resources to pursue soil modeling. In these cases, in-situ pressure is inferred from a simple extrapolation approach.
Ormen Lange Onshore Processing Plant
Authors: Kjeldsen Audun
Published: October 2008

The Ormen Lange Plant at Nyhamna consists of well stream processing, gas export compression and condensate offloading to tankers. The gas from the field is conditioned to dew point and heating value according to European specifications, then routed into the export pipeline to Easington, UK, via the leipner field.

Condensate recovered from the well stream is stabilized and stored in a custom-built rock cavern before being shipped from the terminal. Gas and liquid products are metered to fiscal standards before being exported. The process facilities at Nyhamna consist of two gas conditioning and dehydration trains, three export compressor trains and one condensate stabilization train. The plant processing capacity is 70 million standard cubic metres per day (MSm3/d) of sales gas at an initial arrival pressure of 90 bar. Maximum condensate production is estimated to be 7000 Sm3/d.

Before construction could start, a massive civil works task was performed, blasting more than 2 million m3 of rock in order to prepare the plant site and build storage caverns. The construction and installation of steel structures, buildings, pipes, cables and equipment continued throughout 2006, while in 2007 the main task will be to test out the plant before starting production.

By May 2007, the plant will be just weeks away from hot testing, after a three-year construction period with up to 3500 workers during the peak period at Nyhamna. This paper describes how Hydro as operator has undertaken this massive construction task - building one of Norway's largest processing plants - and what this has required in terms of project management. It also includes a short description of how collaboration with the local community has been achieved.

Fig. 1 Island of Gossen, site for the Ormen Lange onshore plant. (available in paper)

Introduction

Nyhamna, on the west coast of Norway in the county of MØre and Romsdal, was selected as the site for the Ormen Lange onshore processing plant. The Ormen Lange installations have been planned, designed and built according to Norwegian legislation and regulations. Hydro's requirements for HSE work have formed the basis for the HSE goals and requirements that have been set.

HSE acceptance criteria were established with regard to the risk posed to the safety of individuals, society, the environment, health, and working environment, as well as the risk of losing material assets. Subsequent HSE analyses document that the plant meets all Authority, Partner and Hydro requirements to Health, Safety and Environment.

The development of the plant has been based on proven and robust technology. The Ormen Lange project has a strong focus on energy efficiency and the reduction of emissions and discharges in order to minimize environmental impacts. Principles of BAT (Best Available Technology) and ALARP (As Low As Reasonably Practical) have been applied.

The calculated gas production availability of the plant, based on historical industry experience databases and operations experience will exceed 97 % once stable production has been established
Soil-Wave Tank Studies Of Marine Soil Stability
Authors: Doyle E.H.
Published: October 2008

Soil instability occurred off the Mississippi River Delta during hurricane Camille due to large wave induced bottom pressures. This paper discusses the effect of such waves on soft clayey soils.

In particular, the paper is based upon the results acquired from a large model tank which was constructed to study the effect of surface water waves on a clay soil under controlled conditions. The primary motivation for the tank studies was to provide a qualitative means by which an engineer could evaluate the progress of instability under wave loading.

Within the scope of the tank study, soil displacement patterns were observed with depth and related to field conditions. Investigations were made into the effects on the soil continuum of wave height and period, soil shear strength, slope variations, and repeated wave loading. Measurements of wave height and period, bottom pressure, and in-situ soil shear strength were obtained to evaluate simple analytical methods for predicting instability.

INTRODUCTION

The sediments of the Mississippi River have strongly influenced the continental shelf offshore Louisiana. The present Birdfoot delta complex began less than 500 years ago and has been building seaward at rates up to 350 feet per year. 1 The accumulation rate of the sediments has exceeded the rate at which the deposits can dissipate the buildup of excess pore water pressure. As a result, the soils around the Birdfoot complex are very soft and underconso1idated. 2, 3 The weak soils in combination with continuing deposition and environmental forces lead to a dynamic system of delta building. The purpose of this paper is to discuss one of these dynamic processes, namely, wave induced soil instability. This phenomena is initiated by waves of sufficient height and period which produce significant pressures at the seafloor. If the surface waves exert enough pressure, the soil may become unstable. Some areas of the Mississippi Birdfoot complex are susceptible to wave induced soil instability, particularly where weak soils are subject to the effects of hurricane - wind generated waves. 4, 5 This paper is based on the results of soilwave tank studies of wave induced soil instability. The primary motivation for constructing the tank was to obtain firsthand observational experience on the effect of waves on soft soils.

Basis for Tank Tests

The phenomena of hurricane - wind generated waves creating soil instability was generally unknown prior to research by Shell Oil Company. Henkel,6 for example, published a slip-circle method of analysis after completing his work as a consultant to Shell in 1970. Scott and Zuckerman7 in their 1970 review of slope instability in the ocean floor briefly reported Henkel's work.
Viscoelastic Properties of Marine Sediments
Authors: Carpenter Samuel H. , Thompson Louis J. , Bryant William R.
Published: October 2008

Because of their high moisture content, marine sediments have characteristics of both solids and liquids. Being neither liquid nor solid it is difficult to evaluate material 'constants using conventional soil-testing equipment .or conventional liquid viscometers. However, these properties must be evaluated if problems such as anchor resistance to motion, submarine bearing capacity, and slope instability problems are ever to be solved.

Before properties can be evaluated, a theory must exist. Nonlinear viscoelastic theory was used and a simple shear device called the shear viscometer was developed. From cores taken in the Gulf of Mexico it was found that the shear resistance of marine sediment was the sum of an exponential function of shear deformation and a function of the one third power of the rate of shear deformation.

The shear resistance can also be empirically related to more conventional tests such as vane shear, moisture content, liquid limit, specific gravity, and the depth from which the sample was taken.

INTRODUCTION

Investigations into the, engineering properties of marine sediments have slowly been increasing. The bulk of published literature has been written from the geological point of view with fragments of information on the engineering properties being available. The recent increase of interest in the marine floor as a construction area has brought about an increase in the amount of study being devoted to the engineering aspect of marine sediments.

One area of rapid expansion has been the field of projectile penetration into marine sediments. Thompson has derived the theoretical expressions for the penetration phenomena. 15 There are several reports and conferences that detail the scope of study being conducted in this field.8,6,,17

The ability of projectile penetrometers to study the nature of soil deposits in inaccessible regions has been shown by Caudle et al.5 The proper use and interpretation of penetrometer data coupled with the knowledge available from laboratory testing will yield much information that could aid in conducting wide area soil surveys very cheaply.

The application of penetration theory to marine sediments has resulted in a need to understand the dynamic properties of these sediments. Of all the properties, it is apparent that viscosity is the term most often discussed when using marine sediments. Dynamic shear studies will lead to improvement in the areas ofdesign of sample devices to take long undisturbed samples of marine sediment,design of penetration anchors and buoy anchoring systems,obtaining soil information in the deep water environment to great depths anda better understanding of the mechanics of marine sediment.

It is apparent that a study of the dynamic properties, with the viscosity term being stressed, will aid in understanding the penetration phenomenon as well as other engineering problems that occur on the sea floor.
Golfinho Project-Well Construction
Authors: Buchner Bas , Bunnik Tim
Published: October 2008

The Golfinho Field is located in the Southeastern coast of Brazil, at water depths between 1,300 and 1,640m and is the first offshore deepwater development in the Espirito Santo Basin. The field has two main oil reservoirs - Campanian, with 40° API oil, and Maastrichtian, with 28° API. The field has been developed through horizontal wells. This paper describes some drilling and completion operations, the equipment used, as well as some lessons learned during the course of the work.

Two kinds of completion systems - conventional and one-trip completion - have been used. Open Hole Gravel Packing was also installed in all the wells to control sand production. The wells which at first flow naturally are also equipped with continuous gas lift and electrical submersible pumps to be used later when artificial lift becomes necessary.

Introduction

The Golfinho Field was discovered in July 2003 by the wildcat well 1-ESS-123. Located at water depths between 1,300 and 1,640 m, it is 80 km away from Vitoria, the capital city of the state of Espirito Santo (see Figure 1). The field was declared commercially feasible in January 2004, after which the Brazilian Regulatory Agency granted PETROBRAS with a license for exploitation. This would be the first deepwater oilfield development project in the Espirito Santo Basin. Two Floating Production Storage and Offloading (FPSO) units were then leased by PETROBRAS to develop the Golfinho Field. The first one, FPSO Capixaba, was leased from the Swiss SBM to develop Module 1 of the Golfinho Field; and the second, FPSO Cidade de Vitoria, was leased from the Italian Saipem to develop Module 2. Both have a maximum throughput of 100,000 barrels of liquid per day.

Module 1 comprises five production wells and three injection wells, all of which have already been drilled and completed. Three of these producers as well as the three injectors were drilled into the Campanian reservoir, with the two other producers being drilled into the Maastrichtian reservoir. Module 2 comprises four producers in the Maastrichtian reservoir, all of which have already been drilled and completed, and four injectors also in the Maastrichtian reservoir, which should be drilled and completed by June 2007. The project also includes the completion of well 1-ESS- 132, in October 2007, to produce gas from the Santonian reservoir to FPSO Cidade de Vitoria (see Figure 2).

Figure 1 - The Golfinho Field (available in full paper)

After connecting well 7-GLF-1HA-ESS to FPSO Seillean, production started, in February 2006, to collect data to allow a better development plan for Module 2. This was the first deepwater light crude to be produced in the Espirito Santo Basin. In May 2006, Module 1 started producing with FPSO Capixaba, to which three producers and three injectors are presently connected in the Campanian reservoir. The two producers in the Maastrichtian reservoir are yet to be connected. Module 2 should start producing with FPSO Cidade de Vitoria by June 2007, then consolidating Espirito Santo as the second largest crude-producing state in Brazil.