bluuebunny/crossref_metadata_2025 huggingface dataset:
The limits of reliability theory and the reliability of limit state theory applied to pipelines
Authors: Palmer Andrew
Published: October 2008

Two distinct concepts have been developed in general structural engineering and are now being applied to pipelines. Limit state thinking focuses on conditions that directly threaten the security or operability of a system, and have already been adopted into several codes applicable to offshore pipelines. Reliability theory attempts to quantify the safety of a system by statistical arguments.

The paper examines how far limit state methods can be exploited in marine pipeline engineering without underpinning them by reliability theory. It explores this application of reliability theory, and suggests that in this instance - as in many others - the data needed for confidence are not available (and in many instances can never be available). As in structural failures generally, a majority of pipeline failures are beyond the reach of reliability theory. Paradoxically, this fact may strengthen the case for the adoption of less conservative requirements on limit states, because the real increase in risk is often zero m extremely small.

These arguments are then applied to a discussion of the allowable circumferential stress in pipelines where traditional design factors have often been copied from code to code.

Introduction

This paper explores the application of limit-state and reliability methods, primarily in the pipeline industry. These concepts are widely applied in other areas of civil engineering, notably in steel structure design and in concrete design, and in geotechnics. pipeline engineering has 10 some extent lagged behind in this development, at least in its more explicit forms, though it cart be argued that some of the methods customarily applied to pipelines apply limit state ideas implicitly. Limit state concepts have however influenced the Dutch code NEN3650, the Russian SNiP 2.05.06-85, the Canadian CSA Z662-94, ANSI B31 .8, the British BS 801 O: Part 3 and the 1995 Germanischer Lloyd rules.

The two groups of concepts spoken of as 'limit state' and 'reliability' are separate and distinct. In a historical perspective, the two concepts have only relatively recently become intertwined and .sometimes confused, not always advantageously.

Limit states

Limit-state structural engineering are completely central, and far from new. A structure can become unserviceable in various ways. It can collapse, bits can off, deflections can damage internal finishes or make it impossible 10 operate, oscillations can be so large that the occupants feel uncomfortable, and so on, Each of these conditions defines a limit state in which the structure becomes unfit for purpose. Engineers have thought in these terms from the earliest times. The Roman engineers who designed aqueducts like the Pent du Gard must have asked similar questions how do 1 proportion the arches w that they do not be lapse as soon as the is removed, is there a risk of by crushing, is there a risk of progressive distress because of settlement of foundations, and so on.
Defining Coiled Tubing Limits- A New Approach
Authors: Newman K.R. , Stone L.R. , Wolhart L.C.S.
Published: October 2008

The burst, collapse and axial load operating limits for Coiled Tubing (CT) are currently established using the Von Mises incipient yield criterion. This criterion has historically been used to calculate the limits for oil country tubular goods (OCTG), The limits according to this criterion are based on the point at which the pipe material reaches a load state in which it begins to yield. Because of the bending that occurs when the CT is spooled on and off the reel, and when it is bent over the guide arch, the CT is already far beyond the yield point before it enters a well. Thus, this criterion does not really apply to CT.

This paper describes a research project currently in progress, The purpose of this project is to define a new set of CT limits based on criteria other than 'incipient yield'. This new approach to setting CT operating limits takes into account the internal residual stresses in the CT which are a consequence of repeated bending cycles and the accompanying change in material properties.

Introduction

The use of the Von Mises incipient yield criterion to establish CT limits is discussed in detail in Refs. I through 4. This criterion calculates the tri-axial stresses (axial, tangential and radial) caused by the forces applied on the CT due to the following:axial force (tensile or compressive),internal pressure,external pressure,bending due to helical buckling.

The tri-axial stresses caused by these externally applied forces and pressures are combined using the Von Mises criterion to calculate the Von Mises stress, ?vme. This combined stress, ?vmeis then compared to the yield stress, ?ym CT, P, which is determined from a uni-axial pull test on a sample of the CT. When ?vme reaches ?ym, it is assumed that the CT material will begin to yield. This point of 'incipient yield' is currently used by the CT industry to determine the burst. collapse, tensile and compressive limits that the CT can be subjected to.

However, this method ignores the internal residual stresses in the CT caused by the bending that occurs when the CT is bent on and off the reel and over the guide arch. These esidual stresses cause yielding to begin much earlier than predicted by this method.

The material used to make CT has a well-defined yield point in the axial direction. However, beyond the yield point ?yp, the Bauschinger effect and work softening change ?yp and make it less well defined. Also, in the tangential or hoop direction may not be the same as ?yp in the axial direction.

The Gas Research Institute (GRI) has funded a research project to understand and model the material characteristics and to develop an improved method for setting CT limits.
Coiled Tubing Deployed ESP on the Auk Platform
Authors: Stewart D.W. , Centrilift Paul Watkins , Hottslag R.J. , Hudson A. , Wee P.Y. , McCleery B.
Published: October 2008

In March 1995, what is believed to be the worlds first offshore coiled tubing deployed electrical submersible pump (ESP) was successfully commissioned in well AA-03Sl on Shell U.K. Exploration and Production (Shell Expro) Auk platform in the United Kingdom's Central North Sea. The ESP provides a new and important method of artificial lift for the 21 year old Auk platform, which hitherto had relied upon downhole hydraulic jet pumps to lift approximately half of the platform's oil production. The coiled tubing deploymentproved the viability of performing future work over with or without the assistance or indeed the presence of a drilling package.

The novel completion design successfully catered for the wide variety of customer requirements; Well Engineering for a rigless workover, Petroleum Engineering for reservoir access and Facilities Engineering for a specified flowline height The experience gained during this project will be a valuable input in determining the future artificial lift strategy for this platform and for other prospects in terms of performance, reliability and operating costs.

Introduction

The Auk Alpha platform was brought on stream in 1975, producing from 11 oil wells. The reservoir pressure is supported by a strong aquifer drive and the fields water cut has currently reached 70%, The GORs are low, at approximately 175 sef/bbl with a bubble point of 680 psi. The existing method of artificial lift is by wire line retrievable ?downhole hydraulic jet pump, However, due to the limited capacity of the permanent artificial lift (PAL) system, no more than three wells could be lifted simultaneously. It was against this background that the decision was taken to proceed with a trial ESP installation as a complementary method of artificial lift. After deciding to use an ESP pump on the Auk (the first within Shell Expro) the method of deployment had to be considered, conventional deployment versus cable or coiled tubing deployment

The preliminary work showed that using either cable or coiled tubing as the means of deployment for the ESP could give rise to significant savings. Opex reduction of 20% on future workoversInstallation times reduced by 50%. Bedding reduction of circa 100 mandays per workover

The use of cable or coiled tubing deployment was also an opportunity to utilize new technology whilst being aware of the risks involved capitalizing on the work already done with large bore coiled tubing by Shell Expro in the Southern North sea.

An invitation to tender was prepared which invited companies to tender for the supply and installation of all components for the completion excluding the tubing hanger and wellhead. They were also required to supply a Project Engineer to work with the Shell Exploration project team to bring the proposal to fruition. After evaluation of tie submitted tenders a pump manufacturer was selected.
Partnering in Practice: Deepwater Pipelay Gulf of Mexico
Authors: Williams Mandy S. , Eckert Michael Don
Published: October 2008

The Mustique flowlines are dual 3-inch diameter pipelines located in 832 feet of water in Garden Banks 236. The Shasta flowlines are dual 4-inch diameter pipelines and are located in 1,040 feet of water in Green Canyon 6. A total of four pipeline end termination skids and 50 miles of pipelines were installed under a partnering agreement between the Lease Operator ('Operator') and its pipeline installation contractor ('Contractor'). The Operator (Hardy Oil & Gas USA, Inc.) represented itself as well as one other working interest owner (Samedan Oil Corp.) in the Mustique project, and the Shasta project included a third working interest owner (Texaco Exploration & Production Inc.)

The most technical challenges of the project were the laying of dual flowlines from the Contractor's reel barge, attd the installation of the flow lines past an intermediate wellhead, as was the case in the Shasta project. The installation of dual termination skids at the intermediate wellhead also required a considerable amount of technical expertise.

The Operator's objective was to achieve specific contracting goals that resulted in cost-effective work that met or exceeded the accepted quality standards of the offshore construction industry, and also to provide a means to maximize the value of each participant's resources and expertise. Partnering, a non-bidding contracting approach, on the Shasta and Mustique projects enabled both the Operator and the Contractor to work together to share the risks involved in the installation of offshore pipelines, as well as share the savings that were realized as a function of working together.

Introduction

'Partnering' has become one of the more popular industry buzz words, not just in the energy sector but throughout the business world. The term 'partnering:' which is often usedinterchangeably with 'alliance' and 'teaming,' is a term the attorneys would prefer we not use as it can be confused with a legal partnership. The partnering arrangement that was used for the Shasta and Mustique projects was not a legal partnership, but rather a carefully developed Project Management Team ('Team') consisting of representatives from the working interest owners in Green Canyon 6 and Garden Banks 236 and the suppliers of equipment and services as they were selected. (Fig. 1) This approach is a way of getting back to a simpler, old-fashioned way of doing business on a handshake; a means of taking responsibility for what you do and not allowing the 'letter of the law' to destroy a successful relationship.

Management Buy-in

Partnering cuts across traditional role perceptions, and attempts to replace adversarial positions with an entirely different mindset that in essence requires major cultural change. Operators that feel rewarded for being good watchdogs over equipment and services supplier's activities, and suppliers who prefer to hide behind the safety of externally developed precise bid specifications, have to develop a different paradigm
The Application of 3D Seismic Technology to Reservoir Management. Some Recent Examples
Authors: Mikulieh M.J. , Macleod M.K.
Published: October 2008

Introduction

Reservoir Geophysics, or the application of 3D seismic technology in reservoir characterization and monitoring, is a diverse subject covering a wide number of descreet applications. In this paper we will see application in three specific examples including:identification of an oil/water interface in a Gulf of Mexico major field, with the obvious extension to monitoring a waterflood,the use of seismic amplitudes as a Iithology indicator to constrain kriging of a reservoir from well data in Nigeria, andthe use of repeat 3D seismic surveys (4D) to monitor a steamflood in Indonesia.

In Figure 1 we show a list of applications of 3D seismology to a variety of reservoir problems. Taken together, we loosely define the sum of these applications as 'reservoir geophysics.

Example 1. Mapping an Oil/Water Contact, Gulf of Mexico.

The first example is from the Bay Marchand Field in the Gulf of Mexico. Bay Marchand is a very large field with production of more than 700 million barrels, to date, and ultimate recovery of about 1 billion barrels. It is composed of more than 500 individual reservoirs. In this example we look at just one reservoir, the '7900'D'. In Figure 2, we show a time-dice from a 3D survey but along the top of the reservoir. The 3D survey was recorded in 1987, tier this reservoir had been under production for many years. Note the varying amplitude pattern on the time-slice. Because the reservoir sand is approximately 70' to 100' thick and encased in thick shales over the entire reservoir area, we expect that a 3D survey, shot before production commented, would show a relatively uniform amplitude over the same area. Instead, we see a varying pattern suggesting water break though near the eater. We interpret the high amplitudes (reds) on the time slice as oil bearing reservoir, and the low amplitudes (blues) as areas where, at the time the way was recorded, the reservoir had already watered out.

In Figure 3, we show a plot of p-wave velocity vs. bulk density from the well data. Observe the nice separation between the oil bearing sands (yellow dots) and the encasing shales (orange 'X's'). Wet sands are shown as red triangles. Straight lines on the plot indicate points of cmstant normal reflection coefficient, and are labeled. We see that the reflection coefficient is 0,2 to 0.25 for the oil sands and 0.1 to O.15 for the wet sands. This data indicates that in good seismic data we expect to see different amplitudes between the wet and the oil bearing sands.

If we would re-record this survey, we should expect to see further changes in the amplitude pattern as the water encroaches from the south, hence we would be able to monitor the waterflood. However, at Bay Marchand we have not yet recorded a follow up survey for this purpose.
Using Multiple Time Lapse 3D Seismic Surveys for Fluid Characterization in Consolidated Sandstone Reservoirs
Authors: Moorelchevron David E.
Published: October 2008

Analysis of wireline sonic and density measurements of a study well in a h a y consolidated sandstone reservoir shows changes of only 2-8 microseconds/ft increase in transit time and .lg/cc increase in density as water saturation (Sw) changes from 10% to 100% as oil is replaced by brine. The zero offset acoustic impedance between the reservoir and non-reservoir material (encasing shales) shows a 3%-5% increase in impedance contrast over the same changes in water saturation (Sw). Forward seismic modeling of the acoustic logs that change as a function of water saturation from 25% to 100% shows detectable changes in thereservoirs' seismic signature both prestack and poststack. These changes range from 10%-35% increases in amplitude and reflection strength as water saturation increases creating a "dun spot" condition. Seismic reprocessing of a 1982 and a 1991 2D seismic line through the study well confirms themodel predictions of stacked seismic amplitudes of the reservoir. Subsets of a 1982 and a 1995 3D survey covering the study well were normalized to each other using poststack processing techniques. The 3D "region grown"' reflection strength difference map, extracted along the horizon identified by the seismic forward modeling and confirmed bythe 2D seismic test, shows changes in reflection strength that, at least on a gross scale, relates to the production data in the study area.

Introduction

The use of multiple time lapsed 3D seismic sweys for the analysis and characterization of fluids in reservoirs of aproducing field has emerged as one of our most important technical developments in the oil and gas industry for thls decade.

Recent published case histories show that time lapsed 3D seismic surveys can track the movement and change of fluids in porous unconsolidated sandstone reservoirs. This successhas been achieved primarily because of the large effect that fluid types such as gas, oil, and water have on the acoustic impedance of this type of reservoir relative to its encasing material (usually shale).

Can time lapse 3D seismic data be used in consolidated sandstone's for fluid movement and characterization wherethe effects of fluid types on the acoustic impedance of the reservoir is small?

This paper will show that one can identify and quantlty the seismic response as a function of fluid type and saturation of a consolidated sandstone by using seismic forward modeling techniques with well log data measured at a study well. Coupled with newly developed seismic processing techniques that can enhance and detect even subtle changes in acoustic impedance, the paper will then show how the time lapsed 2D data sets compare to the modeled seismic response of the log data at the study well.

Upon confirmation of the time lapsed 2D seismic data to the model seismic data, the paper will then show how the study progressed to a time lapsed volumetric evaluation of the reservoir using subsets of 1982 and 1995 3D surveys over the study well.
Recent Advances in Deepwater Gulf of Mexico Geotechnical Investigations
Authors: Dutt R.N. , Hamilto T.K. , Pelletier J.H. , Doyle E.H.
Published: October 2008

The methods and the technology for deepwater geotechnical investigations in the Gulf of Mexico (GOM) have evolved over a number of years, and this evolution has been punctuated by several technological advancements. Deepwater geotechnical investigations are now pushing the limits of present capabilities, both in terms of drilling and in situ testing tools. More efficient and advanced tools are being developed to keep pace with the ever increasing water depth requirements and the related technological challenges. This paper describes some of the recently developed tools. Where existing tools have been modified, both the shortcomings and improvements are discussed, The tools described in the paper include the small-diameter piezoprobe, wireline hydraulic fracture tool, Halibut II remote vane shear system, and the long-stroke cone penetrometer system, whichis still in the initial stages of development. Also described in the paper are the ongoing joint industry projects that are part of this tool development effort. Investment and continuoustool development will make it possible for the geotechnical community to meet the future challenges in 2000-m to 3000-m water depth.

Introduction

The oil and gas industry continues moving into ever deeper waters of the Gulf of Mexico. The enthusiasm demonstrated in recent rounds of deepwater lease sales suggest that the industry is now prepared to invest in deepwater exploration and production.

The march into the deep waters of the Gulf of Mexico began in the mid to late 1970s, and the journey into deeper waters continued through the 1980s (Pelletier et al., 19%). Geotechnical investigations were targeted at developingdesign information for both fixed platforms and compliant tower foundations. Beginning in the late 1980s, the scene changed from exploring prospects in less than 600m of waterto those in water depths exceeding 850 to 900m. The deepest water depth for a geotechnical investigation to date has been at Shell's "Mensa" prospect (1616m). The foundation scenarios for these deeper waters have changed to subseatemplates and tension leg platforms (TLP).

Deepwater geotechnical investigations in the Gulf of Mexico are now beginning to exceed operational limits of existing site investigation systems. The status of the current technology, and the direction the industry has taken to develop systems and tools to meet the deepwater challenges, are described in subsequent sections of this paper.

Evolution of the Deepwater Geotechnical

Investigation Practice

Geological and geotechnical investigations performed to date in the deepwater Gulf of Mexico have identified an overall very complex environment. The complexity is primarily the result of the upward movement of salt diapirs which have produced extensive zones of steep slopes, faults, fluid expulsion areas, rocky seafloor, eroded seafloor, chemosynthetic communities and other features which make development of oil and gas production facilities challenging, if not impossible.
Can Poor 3D Sampling Lead To Successful Results ?
Authors: Davies Kevin J. , Hampson Gary
Published: October 2008

Traditionally seismic spatial sampling has been restricted by operational constraints. Typically shot sampling has been poorer than receiver sampling, yielding non-optimum stacking geometry and aliased contaminated data. Recent advances inthe understanding of the effects of sampling in seismic data and the introduction of techniques that allow interpolationbeyond aliasing, have permitted the pseudo-creation of optimum geometry or 'stack array' from non-optimum acquisition geometry.

Two examples are used to show how careful handling of aliased energy and stacking geometry can yield apparently successful results from non-optimum sampled data.

The first example is taken from a deep water environment NW of Britain. Data were acquired with a flip-flop source yielding a sub-surface shot interval four times greater than the group interval. In addition the poor sampling intervals lead to the recording of severe spatially aliased water bottom multiples. Application of a spatial antialias filter within the common shot domain followed by interpolation beyond aliasing in the common receiver domain, provides significant improvements to the stack.

In the second example, a 2D site survey vessel was used to acquire a high resolution 3D survey with a shot interval equal to half the group interval. However, the larger than desired group interval passed aliased energy. A combination of interpolation beyond aliasing and spatial antialias filtering applied to both shot and receiver domains permitted theunwrapping and removal of aliased energy. The difference between stacks with and without re-sampling is striking.

Introduction

Seismic surveys are usually acquired with a compromise between theory and finance. Often we design surveys that at least adequately sample in time, but inadequately sample in space. In particular the high costs and limitations on source generation lead to shot sampling that is poorer than receiver sampling, yielding non-optimum stacking geometry and aliased contaminated data. Aliasing is an inherent property of all sampling systems and its effects can be found in a number of seismic processing domains and ultimately in the stack.

The consequences of poor spatial sampling were recognized by Anstey1 in his paper 'What ever happened to ground roll?'. More recently authors such as Vermeer2 and Hampson3 have provided further advances in the understanding of spatial sampling theory, particularly in the two dimensional wavenumber domain. A number of processing strategies that overcome the effects of poor field sampling have been suggested,. including pre-stack interpolation (Spitz4, Jakubowicz5) and post-stack wave number notch filtering (Hampson3). This paper intends to demonstrate that a combination of these processing techniques can lead to successful results.

Sampling Geometry

Optimum symmetrical sampling defined by Vermeer2, is rarely adopted in modem marine 3D acquisition. More commonly, flip-flop source geometries lead to poorer asymmetricalsampling.
Wave Power Use for Island Power Supply by a Backward Bent Duct Buoy
Authors: Masuda Y. , Kuboki T. , Liang X.
Published: October 2008

The Backward Bent Duct Buoy (BBDB) started as a Twin Fuselage BBDB, and was developed to Cylinder float BBDB. Water tank teat indicated a significant output increasing. A sea test in Mikawa bay in the inland sea area was conducted in 1995, and produced 300 watts from a 45 cm wave of 2.7 sec period from a 2.86 m BBDB. Using the Froude Simulation law, and scaling by 10, a wave in the open sea will generate 1,000 Kw from a 28.0 m BBDB.

Introduction

Wave power use is not yet completed except navigational light buoy, but solar power(l50 Watts/ m2) is highly concentrated towave power through wind blows on wide sea surface, and it is stored as swell on sea surface, Table I shows wind and wave Conditions Associated with fully developed sea states. Table I Wind and Wave Power Density by wind speed.

(available in full paper)

In case of 15 m/s in wind speed, wave power through I m width IS equal to solar power in 500 m22 and wind mill area of 50 m 2. Therefore, wave power use will be economical way than solar cell or windmill to use natural energy since energy density is higher. The other hand, wavegives a very strong breaking force to wave power facility constructed on shore, floating wave power device has a merit to avoid such destructive force by following to wave.

Long life and safety mooring were certified by Floating type Wave Power Generator Kaimei by JAMSTEC, Floating platforms by Oil Industry and Fairway Buoy use on sea etc.

The other hand, floating type wave power generator is easy to construct by ship-yard facility, than shore base facility which must be constructed on random shore line. In order to get an economical and safety floating type wave power device, Backward Bent Duct Buoy (BBDB) was developed in this 10 years by corporative study work of Japan, China, Denmark and Ireland. Further interest of India, Philippine and others is given to this study at recent time.

We will ex-plains recent tank study, sea trial and further view for island's and land's power.

Principle of BBDB and circumstance of development. The are various proposals for a Wave Power Generation buoy; Oscillating Water Column (OWC) with buoy is popular, Center Pipe Buoy (Figure 1) is used for navigation buoy, and a turbine generator is used on it. It is known that air output is increased by increasing length of the center pipe. but extending it to vertical direction brings a handling difficulty.

For OWCdevice it is known to open the mouth to wave coming direction but Mr Koichi Nishikawa and Mr Takahiko Masuda proposed that Backward Bent Duct Buoy (Figure 2) which has horizontal long duct to open to backward.
Environmental Impact of Coastal Sand Utilization in a Sniall Pacific Island Nation
Authors: Cruickshank Michael J. , Morgan Charles L.
Published: October 2008

Almost without exception, the small island nations of the Pacific are facing the need to accommodate growing populations in a global environment that imposes significant changes in how people live. Roads, airports, public buildings, durable dwellings, hotels, and shore protection are all part of the considerable infra structure without which contemporary lifestyles cannot be sustained. Most of these structures are built with concrete and island people who have traditionally relied on their beaches to supply sands and aggregates for local construction are finding the source materials in short supply. The island of Tongatapu in the Kingdom of Tonga has for some years been affected by degradation of beaches and hinterland caused by the removal and sale of beach sand. It was proposed that an alternative source of sand be sought offshore and surveys by the regional South Pacific Applied Geoscience Commission located several deposits in the lagoonal area to the North of the island. The potential for ecovery of these sands and the likely environmental impacts were presented in an Environmental Impact Analysis prepared for the government of the Kingdom.

The action studied in the EIA was to replace the mining of sand beaches on the island of Tongatapu with the mining of sand from Basin A, an offshore deposit located in the lagoon approximately 10 km north of Nuku'alofa in 15 m water depth. Review of available reserves indicated as much as 2.6 million m3 of sand, sufficient for 180 years at present rates of usage. A production of 15,000 m3/yr was assumed, using a 4" submerged suction pump, mounted on a 25 meter motorized barge with a capacity of 75 m3. The dredge would operate on site for three hours each working day and discharge to a stockpile at the wharf in Nuku'alofa. Public hearings disclosed a number of concerns including anchoring scars on nearby coral heads; visual effects and operational noise affecting nearby tourist resorts; the social effects of displacing workers presently engaged in beach mining; and possible but minor effects on commercial, subsistence, and sports fisheries in the vicinity ofthe operation. Environmental effects requiring specific analysis were limited to dispersion of fine sediment from the dredge overflow and possible effects on nearby bottom fish and some corals. The most far reaching effect appeared to be the recovery of the beaches from which sand is presently being removed.

The effects of the overflow plume on the dredge may be reduced by using an anti-turbidity overflow system (ATOS) on the dredge hopper and discharging near the bottom. Monitoring would be required to confirm the presence on the bottom of fine sediment from the discharge plume; and monitoring of fish catches or sightings would be necessary to determine any effects on the fisheries, or on prime dive sites. Noise from the operations may be monitored at appropriate intervals. It may also be appropriate to monitor for unauthorized beach mining,
Neptune Project: Regulatory and Classification Issues and Requirements
Authors: Parker W.J. , Ghosh S. , Praught M.W.
Published: October 2008

This paper summarizes the responsibilities of the American Bureau of Shipping Classification Society (ABS), Minerals Management Service (MMS), and the United States Coast Guard (USCG) for permitting a Floating Production System (FPS). Authors present an overview of the permitting strategy and the regulatory framework in regard to the Neptune Sparbased FPS. A list of regulatory approvals is identified for proper planning of the project activities to prevent project delays. A table is provided to show the responsibility delineation, and the administration of paper flow for the approval process. This paper highlights the operator's strategy of approaching the classification society andregulatory agencies to bring them on-board in the early stage of the project.

Introduction

During the last two decades, the offshore industry has been successfully meeting the challenge of producing hydrocarbons in deep water by innovative design of platforms includingcompliant towers, tension leg platforms (TLP), and floating production semi-submersibles. One such innovative concept is the Spar based FPS which has been studied in great detail during the last 4-6 years.

Oryx Energy Company (Oryx) and CNG Producing Company concluded in 1994 that the Spar based FPS waseconomical in comparison to a TLP and other competing concepts for the Viosca Knoll Block 826 field. The Neptune Spar has been successfully installed in Viosca Knoll (VK)Block 826 in the Gulf of Mexico (GOM), located approximately 90 miles south of Mobile, Alabama in 1.930 feet of water. It is located in the MMS New Orleans District of the Gulf of Mexico Region and in the USCG New OrleansMarine Inspection and Captain of the Port Zone of the Eighth Coast Guard District.

For this new concept, the requirements and responsibilities of the primary regulatory agencies, MMS and USCG, were not well understood, nor well defined in the regulations. The Spar structure falls under the "Platform Verification Program" administered by the MMS: therefore, aCertification Verification Agent (CVA) needed to be identified to review the design, fabrication and installation ofthe Spar. The permitting process to obtain the necessary approvals by the USCG were not familiar to Oryx. In discussions with the USCG, several different permitting options were discussed for the project, each with their benefits and drawbacks. These included applying for a Certificate of Inspection (COI) from the USCG with the USCG reviewing the design and conducting inspections; applying forclassification from ABS and a COI from the USCG with ABS reviewing the design and conducting inspections for the USCG, or documenting the Spar in a foreign country and applying for a Letter of Compliance (LOC) from the USCG. Oryx sought a streamlined permitting and inspection strategy and after reviewing the options, chose to apply for class from ABS, with ABS responsible for the design review and inspections for the USCG and to nominate ABS as the CVA for design, fabrication and installation.
Neptune Project: Spar Hull and Mooring System Design and Fabrication
Authors: Kuuri J. , Lehtinen T. , Miettinen J.
Published: October 2008

The Spar hull applied on the Neptune Project is 72 ft in diameter and 705 ft in length. It provides the buoyancy for the support ofthe production 'facilities and well work capability for the production and processing of the hydrocarbons. in Viosca Knoll 826 unit. The hull was designed and fabricated in Pori, Finland. This paper describes the design and fabrication techniques that were utilized to construct and handle the large hull sections. The assembly and inspection processes will be addressed. Due to the large diameter and length of the hull, special transportationtechniques were required. The hull was assembled in two large main sections and then dry transported to the Gulf of Mexico forfinal assembly. Methods used in alignment, and welding these large sections, while floating, will be presented. The special mooring system consists of a six leg taut mooring system composed of wire rope and chain. This marks first use of studless chain for a fixed mooring system in the Gulf of Mexico.

Introduction

The Neptune Spar hull was successfully engineered and built in Finland to two main sections, transported to the Gulf of Mexico for joining, joined floating in water, and the hull was then delivered to Oryx Energy Company (Oryx) floating horizontally at quay side after a 19.5 months contract period. The project was executed on the schedule originally set in an EPC contractbetween Aker Rauma Offshore (ARO) and Oryx as a part of the Neptune field development1.

The Neptune Spar project was a pilot milestone for the long cooperation between Deep Oil Technology (DOT), ARO and J. Ray McDermott (JRM) for developing the Spar type floating production platform. The Neptune project proved the new Spar hull construction techniques and feasibility of a taut mooring system for deep water developments in the Gulf of Mexico (GOM).

Project Execution Outline .

The technical basis for the Neptune hull and mooring contract was built in a preliminary engineering effort mobilized by Oryxafter initial concept feasibility studies. The preliminary engineering phase started in January 1994 and lasted until October 1994. The work included definition of the main dimensions and characteristics for the hull, topsides, and mooring system. ARO was responsible for the development of the hull and mooringspecifications, hull main scantling plans, hull marine system diagrams and arrangements. The best construction method was developed together with the Mantyluoto Works (MW) construction yard. Documentation for the hull structures was submitted to ABS for review and major elements of the hull were approved by ABS in late 1994.

Based on the preliminary engineering work a firm bid was submitted for the hull and mooring system covering project management, engineering, procurement and construction. Oryx decided to go ahead and on 2 February, 1995 issued ARO a lump sum contract for delivery of the Spar hull and the mooring system components excluding the anchor piles (Fig. 1).

Conceptual design work and analysis was carried out by DOT.
Advances In Artificial Lift And Boosting Systems For Subsea Completion
Authors: Camargo R.M.T. , Alves I.N. , Prado M.G.
Published: October 2008

Most of Brazilian oil and gas reserves are located in offshore deep waters. In this scenario, high well productivity is essential. Artificial lift will certainly play an important role in the exploitation of those deep water fields.

This paper describes the most important artificial lift methods, their main characteristics and application niches. It also shows what Petrobras is currently doing in order to make them available for subsea use.

The following methods are analysed:gas lift;electrical submersible pump;hydraulic jet pump;progressing cavity pump;multiphase pump;subsea separation system.

Introduction

Petrobras is the world leader in subsea completion. For subsea application only gas lift has been widely used as artificial lift method, due to its intrinsic similarity with onshore's gas lift method. This similarity comes from the fact that it is driven by a power fluid using roughly the same components for both onshore and subsea application. For this reason, gas lift is today seen as the subsea conventional artificial lift method. Sometimes, gas lift may not be the best method to fit specific field's requirements. This happens, for instance, when there are long distances between well heads and platforms, and the gas injected, even though helping the flow in the vertical sections (well and riser), increases pressure drops in the horizontal section (flow line). Additionally, this method demands compressors and an increase of gas facilities to handle the extra recycling gas, with consequent drawbacks on platform weight and area requirements, which have a high impact on offshore installations costs. Of course, there are other limitations for the gas lift method, but this will be addressed later.

As a major oil company, with large offshore hydrocarbon reserves and more than 60% of nowadays' total production coming from offshore wells, Pepobras is currently feeling the need to adapt some artificial lift techniques, in order to make them available for subsea use as an alternative to the conventional gas lift method. Petrobras believes that each of these options may find some fields with adequate set of characteristics that make them the proper choice for their exploitation.

This paper describes the major characteristics of each method currently under development for offshore use (focusing on subsea applications), the expected characteristics of theirs application niche (advantages and disadvantages), the probable major problems for their extension to subsea use and their current development stage at Petrobras.

Artificial Lift Methods Description

In this item it will be discussed the main characteristics of each method, as well as the difficulties to adapt them to subsea use. What Petrobras is currently doing and planning to do for each method will also be discussed.
Joint Agency Cooperation to Ensure Safety and Protection of the Environment Through Pipeline Inspections
Authors: Bell Theresa P. , Hoffman Catherine M. , Hart James B.
Published: October 2008

The paper describes the use of automatic welding and ultrasonic weld inspection for the deepwater J-Lay of the 18-inch oil and 14-inch gas export pipelines from the MARS Tension Leg Platform (TLP) in the Gulf of Mexico. While automatic welding has seen frequent use on offshore pipelines, its use on deepwater J-Lay was a first, and a significant development effort was undertaken to ensure success during offshore pipelay. To maximize the probability of detecting significant weld defects in these deepwater pipelines, especially those defects with significant through-wall height, Shell specified use of automated Ultrasonic Inspection (UT). This type of inspection can be used to quickly and accurately locate and sue the through-wall dimensions of a defect. These features, in combination with the high toughness of the automatic welds, made it possible to use the Alternative (i.e. Fitness for Purpose) Acceptance Criteria of the Appendix to API 1104, instead of the workmanship criteria of Section 6 of API 1104. As such, a good balance was achieved between, on the one hand minimizing the overall repair rate by not having to repair indications that were not harmful to the weld, an4 on the other hand, maximizing the probability of finding and suing significant weld defects. This first time use of automated UT and application of fitness for purpose weld acceptance criteria on an offshore pipeline project in the Gulf of Mexico goes a long way towards validating the approach as a suitable and cost effective inspection method.

Introduction

The MARS Tension Leg Platform (TLP), a 72%28% joint venture between Shell Offshore, Inc. and BP Exploration, is located in Garden Banks Block 864 in 2940 ft water depth. The two export pipelines, a 14-inch gas pipeline, and an 18- inch oil pipeline were to be installed by J-Lay, using the same J-Lay equipment and lay vessel (the dynamically positioned Derrick Barge DB 50) as used previously to install the 12- inch export pipelines to Shell's Auger TLP'. Dunng J-Lay 165-ft-long pre-fabricated quadruple joints are brought onboard in large storage bins. The quadruple joint is upended in the J-Lay tower and welded in a single station. While on the Auger Project acceptable cycle times were achieved using manual welding (SMAW), the larger pipe diameter and wall thickness on the MARS project warranted an investigation of using automatic gas metal arc welding (GMAW) to obtain much faster joint cycle times than could be achieved using SMAW. The pipelay contractor J Ray Mc Dermott and Shell had negotiated a risk sharing agreement, where both would pay for the incremental cost of automatic welding and UT, but also would share savings resulting from a faster lay rate.
Development of Cyrogenic Marine (In-Water) LPG Export Hose Escravos Gas Project
Authors: Woehleke S.P. , Jones H.T. , Zaffagnini M.P. , Gallant G.
Published: October 2008

A cryogenic marine hose has been developed for exporting LPG at minus 43 degrees C as part of the Chevron Nigeria Escravos Gas Project for Chevron Nigeria Ltd. and the Nigerian National Petroleum Company. The LPG will be stored in a permanently moored floating storage and offloading (FSO) system. Environmental conditions require mooring the export tanker in tandem with the FSO. To transfer the LPG from FSO to export tanker, a program was initiated to develop a floating marine cargo hose suitable for this application. This will be the first application of such.

The development program was conducted in three phases, 1) Engineering, 2) Prototype Hose Construction, and 3) Prototype Hose Testing. The development program was designed to establish confidence in deploying the hose; the test program addressed a wide range of conditions. The development program was successfully completed and manufacture is underway for field deployment in early 1997.

Introduction

Chevron Nigeria Ltd. (CNL) produces approximately 400,000 bbl of oil per day, most of it coming from the Escravos area, offshore Nigeria. Along with the oil is a large quantity of associated gas which is flared. To reduce flaring and to recover the gas and condensates, Phase 1 of the Escravos Gas Project (EGP) was initiated by the joint venture partners, Nigerian National Petroleum Co. (NNPC 60%) and CNL (40%).

Figure 1 depicts the field layout and the EGP phase 1 Development Plan. The EGP consists of three major elements:New Gas Gathering, Compression and Personnel Platforms.New On-shore Gas Processing and Extraction Plant.New LPG Floating Storage and Offloading vessel (FSO) and a Dedicated Shuttle Tanker.

Associated gas from the Okan and Mefa fields, two of the many in the Escravos area, is recover& by the new gas gathering and compression platform. The gas is pumped to the onshore gas processing plant where the recovered gas is processed to produce condensates (which are blended with crude oil for export), natural gas (piped for domestic use in Nigeria) and liquifiedpetroleum gas (LPG, which is pumped offshore to the FSO for refrigeration, storage and export).

The subject of this paper is the program undertaken to develop marine (in-water) LPG hose for transferring the LPG at approximately minus 43 degrees C from the FSO to the shuttle tanker for export to market.

Reasoning for Embarking on the Hose Development Program

During the project definition and conceptual design stage, several configurations were evaluated for storing and exporting the LPG. The configurations evaluated included a deepwater harbor with export terminal and offshore storage and export via an FSO. The offshore storage and export option was selected as the optimal solution.
Development Of A Gas Handling Hydraulic Submersible Pump And Planning A Field Trial, Captain Field
Authors: Cohen D.J. , Dallas J. , Knight F.I. , Woerheide E.A.
Published: October 2008

There are limitations to the amount of free gas that can be handled by high volume downhole pump systems. A new pump design employing axial flow impellers coupled with high speed downhole turbine drive has been developed, and is the first true downhole multiphase pump. This paper describes the staged research and development program leading to the first field trial installation in the Captain Field, in the North Sea. Development and design requirements are reviewed, with the results from laboratory testing in water and nitrogen followed by full scale loop testing in multiphase fluid, including crude, methane and brine. Test configuration is described, and key performance results reviewed. Special testing defined the nature of fluids and rheology related to high rotational speed pumping of viscous crude and brine mixtures in pumps and pipelines.

Following successful laboratory scale testing, design considerations are reviewed for its application in a field trial. Completion design includes provision for open loop flow and access below the pump assembly for coiled tubing intervention. New downhole monitoring systems employ pump and turbine monitors along with pump flow and reservoir evaluation monitoring. The design results in extended range of pump operability, improved reliability, and improved control and reservoir management.

Introduction

As technology improves in horizontal drilling, completion practices, and subsea equipment, the need for high volume downhole pumping systems has increased. Small accumulations or thin oil zones, previously considered marginal, can be exploited economically. But in some applications, pumping systems needed higher gas handling capability because maximizing recovery from individual wells requires larger pressure drawdown. Additionally, horizontal wells located at the top of the productive intervals can encounter free gas caps.

Development of a downhole pumping system that could operate successfully in a gassy environment (higher than 30% gas void fraction), and deliver high reliability was key to exploiting new reserves. This technology could be applied within many major oil compani's existing asset portfolio, such as the Gulf of Mexico or West of Shetlands deepwater environments, and elsewhere in the North Sea. One of the assets that could benefit from this technology is the Captain Field. Although the main area of the field is being developed with Electrical Submersible Pumps (ESP), an isolated gas cap was identified in the eastern section of the field that would limit the reliability of ESP systems, and would limit the withdrawal rate. The field has 19 degree API crude oil, with 88 centipoise (CP) viscosity at reservoir pressure of 1300 psi and 87 deg F.