bluuebunny/crossref_metadata_2025 huggingface dataset:
The Investigation And Repair Of Defective Joints On The Kinsale Alpha Platform
Authors: Murphy Fergal , Smith B.L.
Published: October 2008

This paper describes studies carried out to determine the cause of weld cracking experienced on the Kinsale Alpha jacket in the Cc/tic Sea and the subsequent design and installation of repair steelwork.

An investigative approach was used to create a life history of the jacket from fabrication to in-service conditions. This included consideration of both available field data and theoretical techniques to establish the probable causes of fatigue damage. In particular, the potential influence of fatigue damage due to wind induced vortex shedding vibrations experienced during construction was considered.

The design and installation of stressed grouted clamp repair schemes to five cracked joints, the methodology associated with their successful installation and the various crack monitoring methods used are all presented.

This work demonstrates the significance of wind induced vortex shedding on fatigue life, the use of recently available subsea monitoring techniques and the effective use of grouted clamps in providing a cost effective repair to subsea structural damage.

INTRODUCTION

In July 1990, during under water inspection of the Kinsale Head Alpha platform, severe cracking of the weIds at three joints was discovered. The platform is located offshore Cork, Ireland in the Celtic Sea and is operated by Marathon Petroleum Ireland, Ltd., (MPIL). The jacket is an eight legged structure, installed in 1977 and standing in a water depth of three hundred feet. The cracks were detected in joints at the -158ft, and -217ft, elevations and were in the member end connection welds of long slender horizontal diagonals.

The cause of the weld defects could not be explained as being due to in-service fatigue damage as all of the defective joints had calculated fatigue lives in excess of 1000 years, In addition, inspection of the same welds on a sister structure, the Kinsale Bravo platform, which was of identical design, yielded none of the problems identified on alpha.

Following a redundancy analysis which confirmed the medium term integrity of the structure, MPIL decided to commission studies to examine options for repair and investigate the cause of the weld cracking, Positive results from the investigative studies would provide confirmation of the extent of the existing problem and direction for future inspection programmed on both structures,

During a follow up inspection programme in May 1991, cracking was discovered at two further joints at the -158ft, elevation, again in the end connection welds of long slender horizontal diagonals. As part of this inspection programme, acoustic monitoring transducer arrays and strain gauges were fitted at some of the defective joints in an effort to obtain information on crack growth rates and strain fluctuations over the winter of 1991/92,

After consideration of all of the various options, it was decided to carry out repairs to the cracked joints during the 1992 diving season by installation of stressed grouted clamps.
Concrete Floating Central Facility
Authors: Marshall P.W. , Chabot L.G.
Published: October 2008

The paper describes a large floating production/storage structure for 3000 ft. water in the Gulf of Mexico, which would serve as a central facility for several small TLWJ'S, mini-spars, or subsea templates.

INTRODUCTION, SUMMARY AND CONCLUSIONS

Figure 1 shows the concrete floating central facility (CFCF) which was studied. This would serve as a "mother"facility for several small TLWJ'S (tension-leg wellhead jackets), mini-spars, or subsea templates, in staged development of a giant offshore field, as well as for regional development of the surrounding deep water Gulf of Mexico basin. With smaller motions than a ship-shape FPSO, and no weathervaning, hard steel catenary risers can be used instead of flexibles, while the congestion and complexity of a 28-riser turret and swivels are eliminated. Production facilities would be installed in two stages, to accommodate an ultimate production rate of 150,000 b/d, as well as gaslift and waterflood. Storage of 500,000 bbl, with direct offloading into two DP shuttle tankers, can handle this throughput, with gas export via a small pipeline. The "mother" facility has no wells of its own.

Configuration studies yielded a concrete hull with 200- ft draft, a base tank diameter of 243-ft., and a clover leaf of four 88-ft. tanks at the waterline. These provide 16 points of support for the deck modules, with no Module Support Frame (MSF). First and second-order motions, and the response of several alternative moorings, were subject to two independent analyses. Structural design and outfitting studies were performed by Aker/NC. Two construction scenarios were investigated based on Gulf Coast construction.

Concrete quantity is 0.10 m3 per tonne of displacement, showing the benefit of using shell forms rather than flat walls, as well as the economy of large enclosed volumes. Motions are within previously defined limits for hard risers. Deck accelerations, including the gravity component of pitch, are 0.38g in the 100-year design storm, and 0.09 g in the annual winter storm. The hull can be completed and fully outfitted (including pre-installed interconnecting piping) at dockside, and floated out with a 45-ft. draft. The mooring and its installation accounts for 38% of the total installed cost. Deck modules are lifted on offshore, similar to a fixed platform. Payload can be carried on the CFCF for 50 to 65% of the cost of putting it aboard a TLP, while oil storage capacity can be provided at 80% of the cost for storage in a concrete senisumbersible.

The concrete floating central facility is a robust concept, adaptable to various Gulf of Mexico conditions, and belongs on the list of tankering options for deep water development.

MOTIVATION FOR A BIG CENTRAL FACILITY

At the 1991 OTC, a large discovery in 3000-ft. of water depth, in the Gulf of Mexico, was announced (ref.1). The reported size of the discovery, if fully developed, would be large enough for it to join the exclusive ranks of only seven other giant offshore fields in U.S. waters (ref. 2).
Production Geological Challenges Of Characterizing The Thin Oil Rims In The Troll Field
Authors: Evensen J.E. , Skaug Mari , Goodyear Peter
Published: October 2008

The giant Troll Gas Field is located offshore Norway in water depths of 315–340m. Hydrocarbons are trapped in a shallow Upper Jurassic reservoir sequence comprising sands of excellent reservoir quality. The structure is subdivided into three large eastwardly dipping fault blocks. each with an underlying oil rim of varying thickness. A development plan is approved for the western most fault block area (Troll West Oil Province), which has the thickest oil rim (22–26m). The plan encompasses an extensive subsea development, based upon 18 horizontality completed production wells, the first of which will be drilled in early 1994.

During the past years, Norsk Hydro a.s have through integrated production geology evaluations, reservoir simulation studies and Iongterm horizontal well testing, both proven the producibility of these thin oil rims, and identified the critical elements of a successful horizontal well.

The current production geological efforts are directed towards effective geophysical, geological and petrophysical modeling of the reservoir package, to reduce the uncertain y associated with mapping of the location and geometry of high permeability sands within the oil column. This has involved increasing utilization of the extensive high frequency 3-D seismic datasets. Uncertainty will not be removed by adopting such techniques, so to quantify and understand the remaining uncertain y, stochastic modeling of the reservoir heterogeneities has been conducted in parallel with deterministic modeling.

Evaluation work also continues within the Troll West Gas Province fault block (12–14m oil rim). in an effort to prove The commercial potential for an additional 25–30 horizontal/ Producers.

1 INTRODUCTION

The Troll Field is located offshore Norway, in water depths of 315 to 340 m, some 100 km north of Bergen as shown in fig. 1. The field stretches into 4 Concession Blocks and comprises 2 Production Licences; i.e. Block 31/2 awarded in 1979 under Licence 054 with A/S Norske Shell as operator and the Blocks 3113, 3115 and 3116 awarded in 1983 under Licence 085 with Statoil, Saga Petroleum a.s and Norsk Hydro a.s as joint operators. Other participating companies are Conoco Norway Inc., Elf Aquitaine Norge A/S and Total Norge A/S. The individual shares of the participating companies were unitised in 1986 on the basis of Troll as a single field.

The Troll Field is a major gas accumulation with considerable volumes of oil located in thin oil rims between a large gas cap and a large aquifer. It can be separated into three major provinces:Troll West Oil Province (TWOP) Gas accumulation with an oil rim of 22:26 mTroll West Gas Province (TWGP) Gas accumulation with an oil rim of 12-14 m.Troll East (TE) Gas accumulation with an oil rim of O -4 m.

The outline of the provinces and the distribution of hydrocarbons in place are shown in fig. 2.
Extreme Surge And Mooring Load Of Fps Structures
Authors: Dogliani M. , Pittaluga A.
Published: October 2008

Offset is an important parameter in a compliant structure mooring design. To evaluate maximum offset, commonly adopted methods are based on the assumption that the combined linear and Iow-frequency wave induced off sets are Rayleigh distributed.

This assumption could result incorrect, particularly in those cases, as for instance large volume tension leg platforms and tankers at single point mooring (SPM) where the low frequency component dominates the horizontal motion response.

Aim of the paper is to discuss this assumption and to evaluate the sensitivity of the extreme response of an SPM tanker to the damping, non-linearities in the mooring system as well as to sea state parameters.

To do this, a systematic analysis has been performed and the peak distribution of surge motion and mooring loads have been derived by means of a simplified numerical procedure specifically developed for extreme value evaluation.

The results show that the Rayleigh assumption is not suitable and that particular care is needed in the selection of environmental parameters, including the spectral shape. Even if the analysis has been limited to simple conditions (one degree of freedom, slow drift force only, long crested head sea) the conclusions are believed to hold true in most general cases.

INTRODUCTION

The use of floaters for production end storage is being more and more adopted for both marginal fields and deep water exploitation.

For marginal fields, tankers at single point mooring have became so popular that ad hoc guidelines and regulations have been put in force or are under development with e.g. API, ISO TC7 and IMO MSC Design and Equipment Committee.

As far as the safety of the SPM is concerned, one of the most critical aspects is the mooring system: its loss of holding capacity could lead to the tanker loss with extremely heavy consequences in terms human lives, environmental pollution of investment.

For this reason, it is essential that reliable predictions of the extreme mooring load can be made at the design stage.

Mooring loads are of random nature. Therefore, in order to predict their extreme values, a reasonably accurate, and suitable for design, stochastic model is needed which is not an easy goal to achieve.

As a contribution to the solution of this problem, a sensitivity analysis has been performed with the aim of investigating some still controversial points in presently adopted guidelines, namely the assumed Rayleigh distribution of SPM response peaks and the effects of sea state parameters, in particular the wave spectrum shape and the influence of wave peak period.

NUMERICAL METHOD

According to the simplified character of the analyses to be made, a single degree of freedom system has been adopted to represent the dynamic behaviour of the moored tanker the following equation of motion has been considered.
Centrifuge Modelling And Parametric Analyses Of Drag Anchor Behavior
Authors: Dunnavant T.W. , Kwan C-T.T.
Published: October 2008

A centrifuge and analytical modelling study was performed to gain new insight into the behavior of drag anchors in more-or-less normally consolidated clay soils. The conditions investigated are pertinent to deep-water MODUs and FPSS in "soft clay" regions such as the Gulf of Mexico. The study results show that soil shear strength gradient and lead line type (wire rope vs. chain) significantly impact anchor capacity. Cyclic loading and soil consolidation (anchor soaking) are of lesser importance. Also, it was found that modern, high-capacity drag anchors can provide significant resistance to vertical upIift in soft clay. Standard industry guidelines for predicting anchor capacity do not consider lead line type or soil shear strength gradient and do not permit vertical loads on anchors. It is recommended that anchor sizing guidelines be modified in light of this studyâ??s results.

INTRODUCTION

Existing industry procedures for predicting the capacity of drag anchors [1,2] are based in large part upon the results of field tests performed by the U. S. Navy [3]. These (and other) results have been used to develop empirical charts that relate anchor weight to anchor holding capacity. These charts have some limitations when applied to sizing anchors, particularly those for deep-water moorings:The anchors needed for deep-water mobile offshore drilling units and floating production systems commonly weigh 15 to 80 kips, while the design curves are based primarily upon tests of anchors that weighed 0.5 to 6 kips. Extrapolation therefore is a source of uncertainty.The tests used to develop the curves were performed at a limited number of sites. As a result, the curves are for use in generic soil types such as "soft clay", "sand", and "stiff clay". Site-specific conditions may not be properly addressed.Since the standard curves are based on historical test data, they may not reflect the performance characteristics of new anchor types or enhanced versions of older anchor types.The standard design curves have been developed using short-duration tests in which the anchors were subjected to monotonically increasing loads. Other conditions of potential importance, such as cyclic loading and the period of anchor embedment, generally have not been addressed.

The work reported here was a study of the performance of two types of modern drag anchor in soft clay. The study investigated how anchor capacity is influenced by anchor size, soil shear strength gradient, cyclic loading, anchor soaking, and lead line type (wire rope vs. chain). It included the first tests of properly scaled model drag anchors in a geotechnical centrifuge and limit equilibrium analyses. The results showed, first, that these methods can be used successfully to investigate the behavior of very large anchors in soft clays. Second, the results revealed the significant impact that soil shear strength gradient and lead line type have on anchor capacity.
Zeepipe North Sea Pipeline Welding
Authors: Laing B.S.
Published: October 2008

Statoil's Zeepipe Transportation System under construction is the largest offshore pipeline project ever. The completed system will bring natural gas from the Sleipner and Troll fields in the North Sea to Zeebrugge, Belgium, for onward distribution to customers in mainland Europe. Phase f of the project involved the construction of 1075 km of offshore pipeline including 809 km of 1016-mmdiametefi 24.2-mm-wall pipe. These pipelines were laid in 1991-7992 by European Marine Contractors Ltd. (EMC) off the Semac I and Castori Sei Iaybarges.

The Semac I used the CRC-Evans Automatic Welding system for welding 617 km of the tO16-mm pipe. The welding procedure was developed and qualified at the CRC-Evans facility in Houston, Texas, and the procedure was requalified aboard the Semac 1.

Initially, the mainline welding with the CRC-Evans' system was, on single, 72.2-mm-lengths of pipe because the double joint system was inoperative. However, the majority of the pipe was double jointed on the Semac I and mainline welding with CRC-Evans was on the double- -jointed pipe. The lay rates on Semac I were outstanding, averaging 2.5 km/day for the 199f season and 2.8 km/day for the 1992 season. Peak daily production was 4. 1 km.

DESCRIPTION OF PROJECT

The Zeepipe Transportation System is being developed by Statoil for treatment and transport of natural gas from the Sleipner and Troll fields in the North Sea to Zeebrugge, Belgium, for onward distribution to customers in mainland Europe. The project is divided into three phases:Phase 1 is intended to bring gas from Sleipner "W and the 16/11S platform down to Zeebrugge by 1993, and to install a condensate pipeline from Sleipner "A" to Kalsto in Norway.Phase 2 will tie the Troll field into the system, and will be in operation in 1996.Phase 3 will consist of potential compression facilities at locations to be defined along the pipeline.

The contractor for the Phase 1 work is European Marine Contractors Ltd. (EMC). EMC was responsible for installing the following Zeepipe pipelines:807 km (501 miles) of 1016-mm (40-in)diameter.API 5LX-65 (modified) pipe from me Sleipner platform to Zeebrugge.1.5 km (0.9 miles) of 1016-mm-diameter API 5LX- 65 (modified) stub at the Sleipner platform.39 km (24 miles) of 762-mm (30-inch)-diameter API 5LX-65 (modified) pipe from Sleipner to 16/11S platform.227 km (141 miles) of 508-mm (20-inch)-diameter API 5LX-60 condensate pipe from Sleipner to Kalsto, Norway.

The major marine pipeline construction was done with EMTs two, semi-submersible lay barges, Semac 1 and Castoro Sei. The flat-bottom laybarge, Castoro Due, was used for the beachpull at Zeebrugge and 18 km of the mainline northward from Zeebrugge and crossing the Scheur Channel. The Semac I laid 617 km (383 miles) of the 1016-mm-diameter pipe during 1991–1992 seasons. The Castoro Sei laid 192 km (119 miles) of the 1016-mmdiameter pipe, the 39 km of 762-mm-diameter pipe, and the 227 km of 508-mm pipe.
Development Of Light-Weight Flexible Riser Pipe
Authors: Makino Yoshiyuki , Ishii Kenichi , Fuku Tadashi , Morimoto Satoru , Wada Hiroyuki
Published: October 2008

Light-weight flexible pipe is needed for deep-water offshore oil fields, but there is a limit to the depth at which conventional flexible riser pipe can be used. In this paper we first describe the concept of the limits of applicability for conventional flexible riser pipe and discuss trends in and methods for making it lighter-weight. Then, because the use of fiber reinforced plastic (FRP) for the tensile reinforcing layer is considered the most effective and practical way to lower the weight of pipe, we discuss the conditions and characteristics for FRP for use in the reinforcing layer of FRP riser pipe, as well as the design, manufacturing, and evaluation of FRP riser pipe.

Introduction

As shown in Figure 1, flexible riser pipe consists of an interlocked conduit, an inner plastic pipe, hoop stress reinforcement, tensile reinforcing layer, and an external sheath.1')2)3) Such pipe has come to be widely used in offshore oil fields, where it has become an essential item. As deeper offshore oil fields are developed, this pipe is being used at greater depths. By 1992 oil fields laying 850 m underwater are under developments) and the future is expected to bring the development of offshore oil fields at even greater water depths. Weight is an important factor in floating production systems, and research and development is being carried out in order to create lighter-weight TLP tethers and rigid risers.4)

The use of flexible riser pipe in such deep-water oil fields causes problems of increased laying tension and increased side wall pressure due to the weight of the itself. This has led to the development of methods for installation at great depth5)6and the development of lighter-weight flexible riser pipe.7) Study is underway for replacing the reinforcing layer of light-weight flexible riser pipe with aluminum or a composite material (FRP). Meanwhile, the use of stronger reinforcing steel and the use of FRP are being considered to solve this problem, and this paper discusses the use of FRP.

Key problems

The depth at which flexible riser pipe can be used is limited by the allowable tension and the laying side wall pressure, which depend on the weight of the pipe itself. As shown in Figure 1, flexible riser pipe has a structure in which a plastic pipe is reinforced by multiple layers of metal. The greater the depth at which the pipe is to be used, the greater its weight must be, and therefore the thicker its tensile reinforcing layer must be, but this produces even greater weight, requiring even greater thickness, in a vicious cycle that imposes design limits.

To ascertain the characteristics of the tension of flexible riser pipe in the depths of the ocean, we analyzed the fluctuations in tension produced by waves in a free hanging configuration. Here we considered the maximum static movement assumed for a semi submersible platform and the dynamic response for a significant wave height of 18 m and a period of 15 see, while the pipe is subjected to the use pressure.
Motion And Impact Responses Of Jackups Moving Onto Location
Authors: Miller B.L. , Frieze P.A. , Lai P.S.K. , Lewis T.C. , Smith I.A.A.
Published: October 2008

The objectives and proposed approach for a joint industry study to investigate the problems associated with jack-ups manoeuvring on and off location are described. The study involves assessments of appropriate wave statistics, jack-up motions, seabed response, dynamic impact analyses, and structural evacuation. The results are expected to be harnessed through an on-board PC-based unit.

Results are reported from the motions analyses, soil-structure interaction, end 2-D impacts of the forward leg of a widely used rig onto clay, sand and rock. Conclusions drawn from these individual studies are presented together with a summary of progress on the remaining parts of the project.

INTRODUCTION

Currently, the responsibility for deciding whether or not to move a jack-up onto or off a particular location is taken by the drilling contactor's marine supervisor on board the rig. Undoubtedly, in reaching a decision, the opinions of the barge engineer, tool pusher, operator representative and marine surveyor are all taken into consideration. The decision is based on the practical experience of the personnel and on the limited technical guidance given in the operating manual.

Typically, the operating manual states that the limiting environmental condition is a 5 ft sea. A critical roll/pitch motion curve is sometimes given as a function of water depth. Such a curve is of little use when moving off location. It is also of limited use when moving onto location since it ignores other environmental factors such as current and wind but, more particularly, takes no account of the nature of the seabed, nor of any heave motion. Clearly, different consequences for the rig will result from moving onto soft clay compared with dense sand and hard clay. Touching down on rock will be even more onerous but this aspect is ignored completely in the advice formally offered to the supervisor.

The reason for providing advice when moving onto and off Iocatlon is to minimize the possibility of damage occurring to the legs or jack-houses. Structural damage can occur to these in the event of an unexpectedly severe touch-down.

In an effort to provide more appropriate guidance in such circumstances, the joint industry project described in the next section was initiated. It is now complete although only part of the results can be presented at this time. The study is being complemented by a further investigation concerned with jack- UPS manoeuvring onto and off location in close proximity to a fixed installation. This is receiving separate funding but the results from both studies will be exchanged.

OBJECTIVES AND PROCEDURE

The basic criterion which is to be satisfied is that the risk of exceeding the structural capability of any part of the rig during initial touch-down or lift-off is not unacceptably high. To satisfy this criterion objectively, it is necessary to model these events in some detail. The elements of the approach are illustrated in Fig. 1 and are as follows.
Criteria For Dent Acceptability In Offshore Pipeline
Authors: Fowler J.R.
Published: October 2008

This paper discusses testing and analysis work done to establish the effects of pipeline dents (without gouges) under cyclic internal pressure loading. Operators were surveyed regarding the expected dent shapes and failures from dents that had been experienced. A full scale test program utilizing 12-3/4" pipe with controlled dents and cyclic pressure was carried out. Elastic and plastic finite element analyses was used to determine stresses so that a fatigue analysis could be done.

The results indicate that plain smooth dents less than 5% of the diameter for pipe with a diameter to thickness of less than 30 are not a problem for normal pipeline service. Plain dents are probably not a concern for normal gas line service. An analytical procedure was developed to predict the fatigue life of a pipeline subjected to a combination of plain dents and cyclic pressure.

INTRODUCTION

Extensive research has provided an understanding in the behavior of pipelines subjected to mechanical damage [2–111, The presence of a gouge or the combination of a gouge and a dent has been proven detrimental to the burst strength of pipelines [2–91. The research has also revealed that plain smooth dents, in the absence of a defect, do not significantly reduce the burst strength of pipelines [5,7,8,91. On the other hand, plain dents locally increase the pipe stress due to pressure, Thus, fatigue failures from dents can occur from normal operating pressure fluctuations in the lines over a period of time [7].

The purpose of this research was to develop an understanding of the effects of plain dents subjected to cyclic pressure such that guidelines can be provided which tell operators:Which dents should be repaired immediately?Which dents are of no concern?Which dents could be tolerated for a definable period of time with perhaps a lowered operating pressure?

The main goals of this project were:Review of past failures through historical data [10,12, 13] and published works [2-9,11] to determine the general shapes of the most common dents, and the general operating pressure variations which gas and oil lines experience. From this a "specification" for a typical dent was developed.Conduct experiments to measure fatigue lives of dented pipelines.Predict the stress level and therefore the fatigue life as a function of all relevant variables using the finite element method.

EVALUATION OF EXISTING DATA

One of the objectives of this task was to find specific data regarding failure situations such as dent size and shape, pipeline size, thickness and grade, the operating pressure history of the line, a description of the failure and any special circumstances of the failure. Other data that is necessary for fatigue analysis purposes is the tropical cyclic pressure variations (amplitude and frequency) of both oil and gas pipelines, The sources reviewed were.
Super Stainless Steels: Review Of Norwegian Offshore Practice
Authors: LØvland Paul
Published: October 2008

In the 80's there has been a quiet revolution regarding steels offshore Norway. Duplex stainless steel (type 2205) was installed in hydrocarbon systems (together with AISI 3161 and carbon steel). Highly alloyed austenitic stainless steels (type 6 Mo) were applied primarily in seawater-containing fluids (together with cupronickel). A small amount of highly alloyed duplex steel (super duplex) was used e.g. in a process system.

The reason for this development was expected lower total life-time costs for the oil/gas production, due to improved corrosion resistance of the new steels.

In the 90's it is presumed that titanium, glass fibre reinforced plastics, and perhaps a new super austenitic grade with increased nitrogen content will take a bigger share of the market for sea water containing fluids.

This paper summarises the Norwegian practice with respect to steel properties, requirements, engineering features, and use, the latter including some elucidation of needed quantities. Finally, a brief outlook to future use and competitive materials is presented.

INTRODUCTION

During the 80's there was a quiet revolution in the North Sea regarding materials for offshore production platforms. It related especially to corrosion resistant steels, i.e. stainless steels. Apart from the well known 18-8M0 steel, AISI 316 L, particularly duplex, super duplex, and super austenitic (6 Mo) were used in lieu of carbon steel and cupro-nickel. The first large-scale application was offshore Norway where significant parts of the process and utility systems - piping and vessels - were made of duplex and 6 Mo steels. Shortly thereafter many British platforms were equipped with equal materials.

The main reason for this development that still goes on, is lower total life-time costs expected with these steels. This again depends on the relatively high maintenance costs on the particular type of platforms installed in the North Sea. One must take into account that carbon steel corrodes quickly and may have to be repaired or replaced several times during the lifetime of the platform.

THE SUPER STAINLESS STEELS

Background

When the converter processes AOD (argon - oxygen - decarburisation) and VOD (vacuum - oxygen - decarburisation) were introduced in the 70's, a revolutionary development of stainless steels started These refining methods resulted in very pure steel, especially with respect to oxygen, sulfur, carbon and slag inclusions; moreover, the methods allowed narrow compositional ranges. In this way it became possible to improve e.g. hot workability, weldability, and corrosion resistance of the steels, and more highly alloyed grades could be produced. The improvements were obtained to reduced costs, e.g. caused by less chromium loss during refining of low-carbon melts. Production costs were further lowered by applying continuous casting techniques. Even foundries have today found benefits by using the methods at least for premelted raw materials, and the most advanced of them have invested in small AOD-converters.
Optimized Well Completion Design in the Statfjord Field,North Sea
Authors: Kostøl Petter , Rasmussen J.H.
Published: October 2008

This paper reviews the experience with the original completion of the Statfjord wells. A brief description of the reservoirs and geology is given and the drainage strategy for each reservoir is reviewed.

The workovers' performed due to reservoir requirements, corrosion, sand production and mechanical failures are summarized.

The design basis for an optimized completion is given and the benefits of the monobore completion are reviewed. A typical Statfjord well life sequence is described and finally some production results are given.

INTRODUCTION

The Statfjord field is located in the North sea 200 km northwest of Bergen, Norway on the boundary between the UK and the Norwegian sector. The field was discovered in 1974 and came on production in 1979. Mobil was responsible for exploration, development and production until January 1st 1987, when Statoil assumed operatorship. Statfjord is the largest oil producing field in Europe with a plateau production of around 120 000 Sm3/d.

The Statfjord field is around 24 km long and 4 km wide and consists of the Upper and Lower Brent, Dunlin and Statfjord reservoirs. The field is developed with three large integrated concrete gravity based platforms.

A total of 108 wells has been drilled to date, where 74 are oil producers, and the rest are water or gas injectors. The production from each well varies from 500 to 7000 Sm3/d. The wells were initially completed with a 7" carbon steel tubing and a diameter restricted tail pipe. Tubing retrievals were in many cases required to recomplete these wells. The restricted tail pipe limited the use of through tubing equipment. Some tubing strings also had to be replaced due to corrosion and leaks.

The completion has now been changed to take the full well life into account and to fit the drainage strategy for the individual reservoirs. The 7" monobore completion allows for reliable low cost recompletion and the use of conventional tools for any through tubing operations.

DRILLING PROGRAM

A total of 108 wells have been drilled on Statfjord to date and 3 redrills have been performed. The maximum deviation was initially limited to 60 degrees, but since 1988, high angle, extended reach and horizontal wells have been drilled. A well status is given in table 1. Initially 12 1/4" hole was drilled to TD and 9 5/8" casing set through the reservoir, but most of the wells are drilled with 8.51' bit through the reservoir with a 7" liner (72 wells). At present all the wells are drilled with 8 1/2" hole through the reservoir.

To meet the zone isolation requirements, the 9 5/8" casing or 7" liner is cemented through the reservoir. Concentrated effort has been put into the cementing of the reservoir sections, especially for the horizontal and extended reach wells. Rotating the liner while cementing has been a key factor in achieving good cement jobs and zone isolation.
The Design, Drilling, and Testing of a Deviated High-Temperature, High-Pressure Exploration Well in the North Sea
Authors: Seymour K.P. , MacAndrew Robert
Published: October 2008

Significant quantities of hydrocarbon reserves are contained in North Sea high temperature, high pressure reservoirs. Development of these reserves will require the drilling of deviated wells.

This paper outlines the planning. drilling and testing of the ftrst deviated HTHP well in the UK North Sea.

INTRODUCTION

Within the oil industry there is a general term "high temperature, high pressure (HTHP) drilling". This term has slightly varying definitions in different areas. In this paper the definition used for HTHP drilling is that of the UK Health and Safety Executive (HSE) which has the statutory responsibility for safety in the UK.

This definition is contained in Continental Shelf Operations Notice (CSON) 591 and is that the undisturbed bottom hole temperature must exceed 300°F (149°C) and have a pore pressure gradient in excess of O.8psi/ft or require the use of well control equipment in excess of l0,000psi working pressure.

These wells may be characterised by the following:A rapidly rising pore pressure profile.Convergence of pore and fracture pressures.High gas levels from the source rocks.Loss gain phenomena.Potentially long sections leading to high over balances.Elevated temperatures.

The high temperature requires mud systems, downhole equipment and tools designed to work at elevated temperature.

The convergence of pore and fracture pressures (see figure 1) leads to problems due to the narrow band of mud weight between inducing losses and inducing a kick. This is the aspect of these wells which most probably leads to most trouble.

The high mud weights required for well control leads to a situation, common in the North Sea, where due to the large difference between formation fluid and mud pressure gradients (see figure 2) mud overbalance becomes so high at the bottom of long permeable hole sections that differential sticking becomes likely.

These problems are magnified when drilling small diameter directional holes. The most important single factor is mud, it's weight and system design.

BACKGROUND

Well 22/22b-2 was a farm in exploration well. The objective was to test a Jurassic fault block by drilling to 16,000ft. The well was planned to penetrate the Jurassic in an up-dip location on the upthrown side of the large fault therefore the well had to be deviated (see figure 3).

WELL DESIGN

Casing

The casing design was conventional by North Sea standards (see figure 4 and table 1); Krus and Prieur2 have described the factors in HTHP well design in U.K. waters.

Despite it's conventional appearance there were two major points which had to be addressed. The first was the placing of the 13-3/8" casing shoe. The question here was whether to place the shoe above or below the Palaeocene sands. There are two schools of though on this. One is that the shoe should be placed above the Palaeocene with the top of the deep casing cement below the bottom of the Palaeocene.
High-Precision, Low-Cost Bathymetry Surveys
Authors: Mes M.J.
Published: October 2008

The subsidence bowl at the offshore North Sea Ekofisk field is measured periodically by high precision bathymetry surveys. Phillips Petroleum Company Norway, the operator of the Ekofisk field, installed heave compensated echo sounding equipment on the "Viking Troll" one of the largest North Sea supply boats. With this relatively small investment we can obtain high quality relative bathymetry measurements with the ship's crew as surveyors. Survey data are presented which explain improved survey procedures used to obtain high accuracy bathymetry surveys. Advances in data processing are described. This include procedures to de-tide waterdepth information as well as de-spike the original waterdepth records.

INTRODUCTION

The Ekofisk field is located in the central North Sea. It is oil and gas producing field. Hydrocarbons are produced at a rate of approximately 200,000 bbls per day from three offshore platforms on the field. In November 1984 subsidence in the Ekofisk area was observed and programs to measure the subsidence and its progression were subsequently developed.

We conduct regular bathymetry surveys to check the development of the subsidence measurements of a relative accuracy in excess of what is customary for this type of survey work. Renting a crew and a survey vessel periodically to conduct such a survey is expensive. For that reason we decided to install a GPS navigation system, a digital Navisound 2000 echosounder and a heave compensator on a supply boat on long term contract to us, the m/s "Viking Troll". This vessel is a 3000 ton supply boat. In combination with other work such as platform standby, duty and freight service this boat is ideally suited to conduct bathymetry survey's during periods when there is no higher priority work for the vessel.

Our reference Greater Ekofisk area survey consists of 1200 kilometers East-West and North-South survey lines over the Ekofisk, West Ekofisk and Eldfisk area. The survey line spacing is one kilometer for the general area and 500 meters near Ekofisk and West Ekofisk.

From the Navstar Global Positioning System (GPS) the geographical position is obtained and supplied to a portable computer (PC) every four seconds. Apart from a positioning system the GPS system also supplies clock and calendar information. Because this information is independent of PC settings, we use the GPS system also for time tagging the bathymetry information. The PC polls the echo sounder and heave compensator for waterdepth and ship's heave information. Data are stored on diskettes and on the PC hard disk as a backup.

The survey lines are pre-programmed when the survey on a particular line is system and type in the survey line number. started, the vessel crew switches on the On a monitor mounted near the helm, the ship's position with respect to the ideal position is shown on a map which also shows the platforms in the area and the survey line. The orientation of the map is such that the end point of the survey line is always at the top of the screen.
Geotechnical Aspects Of Bucket Foundations Replacing Piles For The Europipe 16/11-E Jacket
Authors: Tjelta Tor-lnge
Published: October 2008

A major departure from traditional foundation piles for jackets is planned for the Europipe 16/11-E riser platform in the North Sea. Scheduled for installation in the summer 1994 in 70 m water depth, the jacket will have no piles. The permanent foundation will consist of a 12 m diameter mudmat at each of the 4 corner legs fitted with skirts projecting down from its periphery. This new concept will use suction to achieve the fill penetration depth of 6 m. The structure will not rely on gravity platform principles only, but will use passive suction generated by tension load to resist the overturning moment from environmental forces.

INTRODUCTION

Jacket structures have always been supported and tied down to the sea bottom by piles. Only one known steel structure is different, the Maureen steel gravity structure, ref. Agostoni et al. (1980). With the exception of Maureen, alternatives to piled steel jackets have not been available.

The riser platform now under construction for the Europipe gas pipeline in block 16/11 has its piles replaced by bucket foundations, see Fig, 1. In each corner of the four legged jacket the mudmat has been equipped with 6m steel skirts projecting down into the soil. Baerheim (1994) presents further structural details. Even though skirted mudmats are not a new type of foundation since it has been used for a number of jackets to secure on bottom stability, they have always represented a temporary solution prior to pile installation, probably because of a reluctance to accept that tension capacity is available in soils. Tension capacity refers here to the uplift resistance of an object being retrieved from the sea bottom within a limited time period.

This uplift capacity is well documented in clay and is the basis for the skirted concrete foundation units used for the Snorre TLP, ref. Andersen (1992). For sand the same uplift capacity is less accepted in the industry, but development work supporting the Europipe jacket foundations has given confidence in this new concept, called in this paper bucket foundation.

The adequateness of a bucket foundation, from a geotechnical point of view, for supporting a jacket on strong soils can be shown in two example calculations for clay and sand: Given a steel plate with dimensions 2×20m and 25rnm thickness. This plate can theoretically provide bearing capacity in three different ways:A vertical plate penetrated into the soil,The same plate rolled as a pile andThe plate laying flat on the ground.

For a clay with undrained shear strength of 100 kPa. For a dense North Sea sand, the capacities correspond to the values in Fig. 3(available in full paper). From a theoretical standpoint, the flat plate resting on the surface is the obvious choice.

Since the non-stiffened flat plate is not the practical way of supporting structures, a structural compromise can be the inverted bucket which has the highest capacity of all the alternatives.
Captain Extended Well Test Program: Project Management And Execution
Authors: Lovaas W.L. , Weller C.N. , Huddleston Wayne , Wells Brian
Published: October 2008

Extended Well Tests (EWTs) are gaining increasing recognition throughout the offshore industry as a useful tool for evaluation of field development prospects. These tests, which can range from a few weeks to several months in duration, provide valuable data for reservoir evaluation and design of field development facilities. This paper describes how a contractor serving as project manager supported Texaco North Sea (UK) Company in the planning, organization and execution of a fast-track EWT at the Captain field prospect offshore Scotland.

INTRODUCTION

In November 1992, Texaco North Sea (UK) Co. awarded a contract to Oceaneering to perform project management services for an extended well test (EWT) of its Captain prospect. Captain is located in the Moray Firth, Block 13/22 of the UK sector, 90 kilometers east of Wick, Scotland, in 107 meters of water, Fig. 1.

The field was discovered in 1977 when an exploratory well encountered 191 feet of oil-bearing sand. Further delineation followed in 1989 and 1990 with additional wells. A well to the north in 1989 found 93 feet of oil sands and flowed at 740 BOPD using an electric submersible pump (ESP). It was determined that horizontal wells were necessary if commercial production rates were to be achieved. In 1990, one horizontal well was drilled. Again using an ESP, it produced 6,500 BOPD of heavy 19Degree API gravity oil. From this and other data it was theorized that there might be about 200 million barrels of recoverable oil in the field.

The EWT program was originally scheduled to commence with the drilling phase in January, 1993, and to conclude following a 90day extended well test in September. During the test phase, the produced crude would be Processed by equipment installed a board a semisubmersible drilling rig and exported to a storage tanker as clean stabilized crude oil.

The purpose of the extended well test program was to confirm the magnitude and producibility of the Captain field. Test results would be used to determine sustainable crude oil flow rates and the probability of early water cuts which would impact field economics. This information would contribute to design of the eventual field development program and facilities. It was very important to test the oil and water separation techniques the high viscosity crude with the ESP-induced emulsions.

The main task a fix the EWT program included the following:Establish appropriate management systems and ProceduresFinalize vessel and hardware subcontractsFinalize flowline design and submit it to regulatory authoritiesDirect requisite rig modificationsto accommodate the process facilityEnsure timely detail process design and fabrication.

The main EWT system components used during execution of the well test program were: the spread-moored semi- submersible which drilled the wells and later served as the test platform for the process equipment; the process system; the flexible export flowline and the dynamically positioned storage tanker, Fig. 2.