bluuebunny/crossref_metadata_2025_split huggingface dataset:
Gryphon Drilling And Completion Design
Authors: Stewart A.A. , Boudreaux B.A. , Park J.N. 
Published: October 2008

ABSTRACT
The Gryphon Field is the first substantial development on the United Kingdom Continental Shelf to reach production where most producing wells are horizontal (Ref. 1).
The reservoir is relatively shallow at 5500 ft subsea. Reactive shales and generally weak formations overlay the highly permeable reservoir sands, and both water and gas in the reservoir have high vertical mobility. These combined factors presented challenges for effective completion design.
In addition to horizontal wells the development programme included conventional producers, water injectors, an aquifer source well and a gas utility well. The unconsolidated and normally pressured nature of the reservoir dictated sand exclusion design in all wells and artificial lift in the oil producers and aquifer well.
Additional requirements for subsea development and easy well interventions led to an innovative subsea tree system (Ref. 2).
This paper describes how the above factors were considered in developing the well designs. The necessity for close coordination within the operator's disciplines is illustrated.
The overall product is a unique combination of drilling and completion designs which incorporate innovative applications and systems.

DRILLING

Wellhead Arrangement
As shown in Figure 1 the wellhead cluster is positioned 1500m from the Gryphon 'A' production vessel. This proximity created some interference between the Gryphon 'A' anchor-pattern and a standard eight-anchor semi-submersible anchor spread. Two 48" piles were cemented into the seabed with 590 ft of anchor chain buoyed at the free. end. This allows any rig to attach two anchor chains for safe mooring and solves the problem of interference. Setting the piles cost less than adding umbilical and flowline lengths to avoid anchor interference.
To set the piles a 36" hole was drilled then opened out to 60" with a specially built hole opener. The piles were run on drill pipe and cemented with a modified grouting slurry. Accurate positioning of the top of cement was achieved using a radioactive densometer. This was recovered on a tugger with an ROV retrieval system as back-up.
The wellheads are arranged in a cluster with a 10 metre separation. This arrangement had a lower cost than a conventional template arrangement and reduced the risk of collision between wells while drilling, It does require more accurate rig positioning systems than satellite systems to spud each well. An acoustic transponder array on the seabed positioned the spud assembly with relative measurements accurate to ±0.75 ft.

Drilling Hazards
From the 15 appraisal wells and 10 geological sidetracks drilled in or around the field a combination of distinct drilling hazards has been identified. These include:Near-surface boulder bedsUnconsolidated sands in surface holeWater-sensitive Eocene claystones above reservoirUnconsolidated reservoir sand with very high permeabilitiesUnpredictable reservoir top and intermittent shales within the reservoir body
Operational Experience Gained From The Central Brae Subsea Field
Authors: Sapp S.J. , Gomersall S.D. 
Published: October 2008

ABSTRACT
The size of the field discoveries made in the North Sea in recent years has declined dramatically. With the 10w oil price man y small fields are not viable stand alone developments. The North Sea has a large, well developed infrastructure of production facilities and pipelines. With man y platforms now operating halo w optimum production rate, subsea tieback of these small fields utilising the available processing capacity is the most economically attractive means of development.
This paper presents a history of such a field development. The Central Brae field is located within the Brae complex of fields, 155 miles north east of Aberdeen, and has been developed by means of a subsea facility tied back to the Brae Alpha platform.
A great deal of experience has been gained through the field development, not only in subsea operations but also in completion and template design and oparating philosophy.

INTRODUCTION
The Central Brae field was discovered in 1976 by Well 16/7a-3, approximately 155 miles (249 km) north east of Aberdeen, in 350 ft of water (Figure 1) (Available in full paper).
This well formed part of the early exploration programme of what was to become the Brae complex of fields. Final appraisal wells were drilled in 1984 and 1985 following the development of the South Brae field. This field was developed from the Brae Alpha platform.
The Central Brae field is a black oil reservoir of Upper Jurassic age (32° API, 1400 scf/bbl GOR). The reservoir is a relatively compact structure alreally, and following the appraisal phase had been mapped into two regions. The 'proven' area defined by the appraisal wells was estimated to contain of the order of 175 million barrels STOIP (stock tank oil in place), whilst the 'possible' area was estimated to contain 111 million barrels STOIP, The overall liquid recovery was estimated to be in the order of 70 million barrels STOIP. The reservoir fluids posed some potential production problems. The hydrocarbon fluids were highly corrosive (average composition 30% CO2 and 25 ppm H2S) and there was potential for both calcium carbonate and barium sulphate scale deposition.
A feasibility study into the potential development options was carried out in late 1985. At that time, field size precluded development using a jacket or floating production system. A subsea development tied back to Brae Alpha was the only economically viable option. The field is only some 4.3 miles (7 km) from the Brae Alpha platform, and with available process capacity a subsea development could utilise the existing infrastructure with the minimum of platform modifications (Figure 2)(Available in full paper).
A plan of development for the field was approved by the Brae Group partners in October 1987, and approval from the UK Department of Energy was received in April 1988. The plan of development called for the installation of an 8 slot template at the appraisal well location.
An Overview Of The Mobile Bay Project Offshore Facilities And Installation Approach
Authors: Gallagher M.J. , Arthur T.T. , Boening D.E. , Sortland K.A. 
Published: October 2008

ABSTRACT
This paper provides an overview of the offshore portion of the Mobile Bay Project, including a review of the installation methods used. Also included is a discussion of the key focus areas and program elements of the safety process implemented during the Project. The unique aspects of the Project led the Owner to use a different approach to managing the work for a Gulf of Mexico installation. The Owner assembled and led a team of many contractors to plan and complete the multifaceted scope. Most of the work was done on a reimbursable cost basis which allowed the Owner to be highly involved in selecting contractor personnel and equipment, in developing the detailed work plans, and in making the day-to-day decisions during the installation. This approach resulted in a successful installation which met all Project requirements including achieving outstanding safety performance.

OFFSHORE OVERVIEW

Facilities

General
The Mobile Bay Project is the world's largest offshore sour gas development. Located near the entrance to Mobile Bay, Alabama, the development consists of three fields; the Bon Secour Bay field inside the bay and the Northwest Gulf and North Central Gulf fields just outside the bay in the Gulf of Mexico (Figure 1).
In the bay the water is relatively protected and shallow, 13 feet or less, with a muddy bottom. Offshore the fields are in waters up to 50 feet deep with a sandy bottom. The current is strong at the mouth of the bay, swells are typically found in the area, and ten foot seas are not uncommon in storms.
The offshore work was done under rigid environmental stipulations that required all discharges to be collected and barged for offshore disposal. Additional measures were needed to prevent silting of the numerous oyster beds in the area.
There are currently eleven wells with shut in pressures as high as 10,600 psi and with flowing temperatures of 300 degrees Fahrenheit. The produced gas ranges from 10% H2S in one of the Bon Secour Bay wells to only 50 ppm H2S in the North Central Gulf Field.

Production Platforms
Within each field, produced gas from the wells flows through flowlines to a production platform for separation and dehydration. Each of the three platforms is an eight-pile structure supporting a one and a half level deck with the largest measuring 210 feet × 120 feet. The decks were outfitted as a single unit with total weights ranging from 3,700 tons to 4,800 tons. A separate 42 person living quarters platform is bridge-connected to the Northwest Gulf platform.

Well Templates
Each production platform has a separate bridge-connected template for one or more producing wells. There are also five remote well templates, for a total of eight, with the furthest being about 4 miles from the production platform. The templates are 50 feet × 60 feet single-level decks supported by three-legged structures with the well conductor acting as one of the support legs.
Structural And Installation Design Of Plate Foundations For Jackets
Authors: Baerheim Morten 
Published: October 2008

ABSTRACT
A new foundation system for offshore steel jackets has been developed by Statoil. The method is called plate foundations and it replaces the use of traditionally piled foundations. The plate foundation consists of a circular plate placed below each jacket leg. The plate is surrounded by a vertical skirt penetrating the sea bed.
The plate foundation acts in principle as a gravity foundation. Due to the skirts, however, the foundation has a considerable capacity for tension loading even for sandy soil conditions. The tension capacity is due to high suction pressures as the tension loads tries to pull the plate out of the sea bed.
This paper describes the development of the plate foundations, discusses the design and installation aspects of the foundations and describes typical mechanical equipment needed for the foundations.

INTRODUCTION
Plate foundations are in principle not new for supporting offshore steel structures. The Maureen steel gravity platform stands on similar foundations and jack-up platforms stand on either individual spud-cans or large mats. Typical for both these solutions are that they are not designed to support tension loads.
Even though the Maureen platform had skirts for capacity against sliding, the main difference between the gravity foundations and the plate foundations is the design of the skirts to resist uplift loads.
Experiences from concrete gravity platforms, and in particular the Gullfaks C structure with 22 metres deep skirts, have provided valuable background for the design of the skirts, the load transfer mechanisms and the planning of the installation operations.

DEVELOPMENT OF THE PLATE FOUNDATIONS
Statoil first investigated the ability of a gravity foundation in steel jackets to support tension loading for the Veslefrikk jacket installed in 1989. The slender jacket in 175 meters water depth had a problem with on-bottom stability during the installation. The mudmats on the jacket were rather large due to soft seabed conditions, and they had one meter deep skirts for resistance against sliding. Intuitively it was expected that the mudmats would be able to support some tension load. Little information was found on suction capacity, but based on what was available the necessary tension capacity was proven.
The installation of the Veslefrikk jacket was also affected by pile driving problems, which is not a uncommon problem in offshore installations.
Based on the realisation about suction capacity of mudmats and reoccurring pile driving problems, it was felt that the foundations for offshore jackets could be simplified and improved. Thus the work on developing the plate foundations started at the end of 1989.
The initial work was spent on developing typical structural configurations (ref. 4) and determine typicaI area requirements and skirt depth for the foundations.
The geotechnical design is a very important factor of the plate foundations. The development of design procedures and offshore and onshore test programs to develop the technology are described in more detail in ref. 1.
South Timbalier 161A: A Successful Application of Platform Requalification Technology
Authors: Imm G.R. , O&apos;Connor P.E. , Light J.M. , Stahl Bernie 
Published: October 2008

Abstract
Since the early 1970s, risk assessments of older Gulf of Mexico platforms have been performed to recommend and implement remedial measures which improve their chances of hurricane survival. This process has become known as platform requalification. Amoco's requalification process consists of two steps: platform screening to identify potential high risk platforms, and risk assessments of these platforms to evaluate remedial measures to reduce the risk. As a result of a Gulf of Mexico platform screening effort, Amoco's most recent assessment work has focused on its South Timbalier 161A platform. The assessment led to implementation of remedial measures in 1991. These remedial measures, aIong with those implemented earlier as a result of previous risk assessments, were tested when the platform received a direct hit from Hurricane Andrew in August of 1992. The successful structural behavior of the platform in this 100 year storm lends credibility to the platform requalfication process.

Introduction and Background
Hurricane wave height and wave force knowledge was limited when many of the first generation of offshore platforms were designed in the early 1960s. Consequently, the decks of many older platforms are closer to the water than today's designs. Instead of large hurricane waves passing underneath the decks of these platforms, some waves may impact the decks resulting in large overturning loads. This is the main reason why older platforms are at a higher risk than today's designs. Other reasons include the lack of joint cans and the use of K-brace framing, which has less reserve strength than today's more widely used X-brace design1.
Since the early 1970s, Amoco has performed risk assessments of its older platforms. The purpose of these assessments has been to identify and recommend remedial measures to improve an older platform's chance of survival if its relatively low design load is exceeded in a hurricane. The assessments have considered only the structural risk due to environmental overload in a hurricane, and not risks due to boat impact, tire and blast, and human error.
Platform risk assessments consider numerous failure modes including failure of deck legs in bending near the cellar deck, tensile yielding or compressive buckling of brace members, axial pile-soil failure, pile bending failure, and joint failure. The challenge of the early risk assessment work was to predict a complex nonlinear phenomenon with simple linear analysis tools.
The remedial measure which Amoco found to be most economically feasible in those early years was grouting of the jacket leg to pile annulus. This measure was implemented on a number of older Gulf of Mexico platforms. The strength provided by the grout enabled these platforms to survive events such as Hurricane Carmen (1974) with no damage, and contributed to the fact that Amoco has not lost a platform due to a hurricane.
Performance And Testing Of Components Of The Ivanhoe/Rob Roy Floating Production System Mooring
Authors: MacGregor J.R. , Smith S.N. , Paton J.E. 
Published: October 2008

ABSTRACT
Five years of operating experience with a floating production system mooring are described. In-service chain diameter measurements and cathodic protection levels are described.
Detailed examination of removed components shows that wire ropes in a permanent mooring system degrade differently from those on a mobile unit and that careful consideration should be given to minimizing installation damage.
Break testing of 84mm ground wires after five years service reveals a loss of strength of only 0.1% to 0.2% per year. Strength reductions of 1.5% to 2% per year are noted for the winch wires. In this case, the fairleader sections of the winch wires have suffered less damage than the winch sections.
Chain breaking strength data is presented showing that used f02mm Grade 3 chain from the mooring consistently sustained loads some 13% higher than the catalogue breaking strength of new chain.

INTRODUCTION

General
The AHOO1 floating production facility (FPF) has operated on the Ivanhoe and Rob Roy fields in Block 15/21A of the North Sea since July 1989.1,2,3The AH001 was converted from the semi-submersible support vessel Sedco-Phillips SS (a modified Sedco 700 design). The mooring system comprises twelve combination wire and chain lines, secured to piled anchors in 140 metres of water. These lines are arranged to effectively form six pairs of catenaries as shown in Figure 1. The make up of each line is shown in Figure 2, and summarised in Table 1.
Because of the large number of lines, the 100 year return environmental design basis and the high factors of safety, the AHOO1 mooring system is arguably one of the most robust currently in operation in the North Sea.
This paper brings together the original design assumptions for the mooring components, the subsea inspection data, and the results from the testing of removed components.

Operational History
Mooring system performance has generally been good. In particular, the vessel excursion and line tensions are lower than predicted. However, although no line failures have resulted from overstressing, fatigue damage, or corrosion, the AHOO1 has lost a mooring line on two separate occasions.
On both occasions, approval was gained from the Certifying Authority to resume and continue production operations with revised operational criteria appropriate to an eleven line system. On neither occasion was the revised operational criteria exceeded.
The first incident was due to failure of the bolted connection at the bottom bearing mounting on the line 1 fairleader. The fairleader then detached from the column foundation structure and parted the winch wire.
Extensive investigations were conducted to determine the cause of failure, and to assure the integrity of all other components involved. It was concluded that the failure was due to the original bolts being of inadequate section and ductility. The integrity of the mooring system was restored to design levels by correcting these defects.
The Influence Of The Uniaxial Stress-Strain Curve Of Materials Offshore And On Structural Integrity
Authors: Dier A.F. , WhiHock R.T. 
Published: October 2008

ABSTRACT
The new high-strength steels being introduced into the offshore industry have substantially different mechanical properties from traditional structural steels. Since many of the existing design criteria are of considerable age, it is pertinent to examine the suitability of using the same criteria for the new steels. The parameters produced by the standard uniaxial tension test are first reviewed, and the sources of variation affecting the tensile parameters are briefly discussed. The question of the yield:tensile strength ratio is discussed in more depth, and a basic reliability analysis of the behaviour of this ratio with increased strength is presented. The influence of some of the material parameters on the design of components is also considered.

INTRODUCTION
Throughout most of the history of engineering, the limited capabilities of design have been matched by the nature of the available materials, whose properties were highly variable, usually very anisotropic, and in any case largely outside the control of the engineer. However, the last two centuries have seen an ever-accelerating rise in the sophistication of engineering design and in the control over production, fostering a corresponding need for accurate data on the properties of materials.
Although the development of data-gathering might have been driven by the requirements for design, it is not always obvious what parameters should be measured, and what test is most appropriate. Unfortunately, materials testing as a subject has fallen largely out of fashion and tends to be taken very much for granted, despite the importance of the results for design. Of the wide range of tests, the uniaxial tension test is the most useful, and has been standardised for many years. Indeed, it now occupies such a central place in the methodology of design that its results are in danger of being regarded by many engineers not as a guide to performance, but as being sacrosanct. The shortcomings of such a view have been recognised for over fifty yearsl-5
Of particular concern are the effects that such an attitude might have on the deployment of new steels coming into service, whose properties may not be well predicted by the traditional engineering measurements, or whose optimum use may be handicapped by design methods based on old-style steels. The development of steels over the last twenty years has been on substantially different lines from traditional practice, and has necessitated changes in steelmaking that have been nothing short of revolutionary. Accompanying the improvements in steelmaking, the control over processing is now much more precise, which, together with improved sampling and quality control, have resulted in more consistent and better-characterised products.
The main impetus behind the development of the modern steels has been the requirement for improved weldability at higher strengths, which has precluded the traditional route of attaining high strength by using high carbon contents.