bluuebunny/crossref_metadata_2025 huggingface dataset:
Collar Load Support (CLS) Tubing Running Procedure
Authors: Boutwell D.F. , Webre C.M.
Published: October 2008

This paper discusses a significant new procedure for running CRA tubulars that relies on new innovative technology. The procedure completely eliminates all die marks and other mechanical damage that result from traditional running procedures and hardware. This is accomplished through the use of a number of new and innovative devices that rely on supporting the tubing string weight on the face of the coupling.

This procedure, known as the Collar Load Support(CLS) Tubing Running Procedure (U.S. Patent 5,083,356), employs the use of Load Transfer Sleeves(L'f13)to lower the tubing string into the well bore. These sleeves carry the weight of the string under the face of the coupling. The sleeves transfer string loads between elevator and a special landing spear without allowing any radial loads to be applied to the tubular body. The connections are made up power tight with specially built power tongs that employ new technology for gripping both the tubular body and coupling O.D. through the use of friction rather than toothed dies.

Utilization of the procedure requires that additional design considerations of the tubing string (specifically couplings) be evaluated and satisfied, along with the anticipated environmental requirements. The history of the development of the procedure is discussed, and the testing program to prove the feasibility of the procedure is detailed. The resulting data and actual performance of the CLS Running Procedure in a ease study clearly demonstrates the potential for cost savings via reduced wall thickness requirements and increased tubular life in the well.

INTRODUCTION:

Hostile environments found in deep, high pressure gas wells require that extra precaution be taken to extend the productive life of the well. These measures often result in the use of corrosion resistant alloys (CRA'S)to prevent premature failure of the production tubing.

Traditional procedures and hardware used to carry out installation of tubing, rely on toothed inserts or dies and gripping mechanisms that force the die or insert teeth to penetrate into the outer wall of the tubing. The dies or inserts are forced radially inward against the pipe O.D. by the interaction between the tapered bowls and slips into which the dies are fitted. The magnitude of the radial forces is quite high and is influenced by the condition of the slips and bowl along with the lubrication between the slips and bowls. The resulting die marks in the pipe are typically abrupt V-shaped notches. In the process of deforming the material to allow for die penetration, the pipe wail beneath these notches is work hardened, thus compounding the severity of the die marks.

CRA materials are typically restricted to a maximum hardness or hardness range in order to obtain satisfactory corrosion resistance performance. Many industry majors have developed guidelines which limit the acceptable depth of these die marks. Ideally complete elimination of the injurious die marks and associated cold working would permit optimum performance of the CRA material.
Ocean Drilling Program: Results From Ninth Year Of Drilling Operations
Authors: Rabinowitz P.D. , Francis T.J.G. , Baldauf J.G. , Coyne J.C. , Harding B.W. , McPherson R.G. , Merrill R.B. , Olivas R.E.
Published: October 2008

The Ocean Drilling Program (ODP) has completed 52 internationally staffed expeditions and nine years of scientific ocean drilling in search of answers relating to the tectonic evolution of passive and active continental margins, origin and evolution of oceanic crust, origin and evolution of marine sedimentary sequences, and paleoceanography. To address these problems, ODP has made numerous advances in technology for retrieval of continuous undisturbed cores under hostile environmental conditions. ODP curates over 187 km of cored material and associated scientific data bases and publishes results of the scientific expeditions in a continuous series of Proceedings volumes.

During its ninth year, ODP completed its pioneering exploration in the Pacific Ocean and commenced a campaign of Atlantic Ocean coring. Leg 147 sampled Hess Deep in order to understand igneous, tectonic and metamorphic evolution of fast spreading oceanic crust and to understand the processes of rifting in young ocean crust. Leg 148, near the Galapagos, deepened Hole 504B, the deepest hole we have beneath the deep sea floor to 2111 mbsf in an attempt to penetrate oceanic Layer 3. Leg 149, entered the Atlantic Ocean and cored the rifted margin of the Iberian Abyssal Plain in order to study its subsidence history and the age and nature of the ocean-continent transition. Leg 150 retrieved 4034 m of core on a transect of sites off New Jersey aimed at studying late Oligocene through Miocene sea level changes. Leg 151 in the Norwegian-Greenland Sea made use of an ice-support vessel in the Fram Strait region of the Arctic Ocean to investigate high northern latitude ocean's role in global climate and ocean systems. Leg 152 investigated deformation of the lithosphere and mechanisms of magma emplacement on the East Greenland Margin.

Leg 153 is scheduled to drill the lower crust and upper mantle in the MARK area of the mid-Atlantic Ridge; Leg 153, on the Ceara Rise in the western equatorial Atlantic will piston core a depth transect and answer important questions of paleoceanographic significance; Leg 155 on the Amazon Fan will sample several acoustic units to determine their lithologies, facies and ages; and Leg 156 is scheduled to drill a number of holes penetrating the deéollement zone and spanning the deformation fronton the Northern Barbados Ridge. Legs 157 to 165 will continue our Atlantic Ocean exploration by drilling near Volcanic Island Apron of the Canary Islands (Leg 157), TAG Hydrothermal province of Mid-Atlantic Ridge (Leg 158), Equatorial Atlantic Transform (Leg 160), Mediterranean (Leg 161, 162), Atlantic Arctic Gateways (Leg 163), Gas Hydrates on Blake-Outer Ridge (Leg 164) and Vema Fracture Zone (Leg 165). One expedition will visit the SW Indian Ridge in the Indian Ocean (Leg 159).

This paper focuses on ODP'S scientific and technical achievements during its ninth year of field operations and discusses areas of future study.
Gryphon Drilling And Completion Design
Authors: Stewart A.A. , Boudreaux B.A. , Park J.N.
Published: October 2008

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

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

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

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'Connor P.E. , Light J.M. , Stahl Bernie
Published: October 2008

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

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

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.
A Booster Station: Results Of Extensive Testing And Post-Test Inspection
Authors: Cotton J.L. , Stinessen K.O.
Published: October 2008

The complete Kvaener Booster Station has undergone extensive underwater testing in its test tank in the two-phase laboratory at Tiller, Trondheim, Norway.

The whole range of steady state performance testing up to 11 000 Barrels/Day of liquid and/or 7.0 million SCF/Day of gas has proved the basic concept.

Additionally, significant development of the process control system has resulted in understanding and excellent control of both upstream slug flow and pressured low variations from a simulated well scenario and also the downstream pressure/flow variations representing long, undulating flow lines followed by a riser. Handling of foaming fluids has been achieved, including exceptional foam into the compressor.

The paper presents a brief description of the KBS, the test facilities and the results of the testing. It considers the implications to the user/operator, together with the conclusions from the post-testing inspection.

The Kvaener Booster Station is now considered to k qualifield for use on a subsea application.

BRIEF DESCRIPTION OF THE BOOSTER STATION.

General

The function of the KBS is to increase the pressure in a flowing hydrocarbon stream. As such it is a multiphase pump. The KBS however, separates the flow into a pumpable liquid and a compressible gas. The two phases are then increased in pressure in separate pump and compressor, both electrically driven, and both using known and proven technology. The resulting streams at higher pressures can then be recombined into one flowline or sent in two separate flowlines to the receiving facility. The KBS is divided into three main modules; separator and cyclone scrubber module, pump module; and compressor module. These can be individually sized and configured to suit the application. Figure 1 is a cutaway section of the first KBS, which has a nominal capacity of 10000 Barrels/Day of liquids and 12000 ACF/Hr (or approximately 4.5 million SCF/Day) of gas. The whole KBS tits inside the standard API guide-post spacing, is about 12 meters (40 fi) high and weighs about 50 tonnes as shown in figure 1.

The modules are mounted one above the other with the pump at the bottom, the separator in the middle and the compressor at the top.

Although the KBS at first sight seems complex, it is in fact very simple compared to similar topsides equipment and even the apparently simpler multiphase pump, when all auxilliary equipment has been added. All non-essential equipment has been eliminated. The remaining equipment has been configured in detail by some of Europe's leading suppliers. Only through these routes has it been possible to build in the necessary level of inherent reliability. Maximum use has been made of the subsea environment of water under pressure, and the fact that it is inaccessible.
Evaluation Of Leg Damage Risk For Jackups Going On Location
Authors: Smith I.A.A. , Frieze PA. , Lai P.S.K. , Lewis T.C. , Miller B.L.
Published: October 2008

The objectives and procedures of a recently completed joint industry project (JIP) examining jackup behaviour during touchdown are briefly described. Aspects covered include motions analysis, spudcan-soil behaviour, dynamic impact analysis, leg structural capacity and risk calculations. lhese features ha ve been incorporated in an analytical program, GMIMPACT, intended for use on-board jack-ups.

The emphasis in this paper is on describing the results of the work as they relate to the limiting seastates applicable to a typical jack-up manoeuvring onto location. The variables which were considered were leg length, wave height and period, touchdown operation duration and seabed type.

The paper demonstrates that, by consideration of site specific conditions, the time waiting on weather to move onto or off location can be reduced in a number of circumstances.

INTRODUCTION

A Joint Industry Project (JIP) has been carried out to investigate the behaviour of jack-ups during touchdown. This work comprised two phases and has been undertaken with the dual aims of increasing safety and of reducing weather downtime.

Existing guidance on touchdown is of a very limited nature, the decision as to whether or not to proceed with the operation often being determined by the adoption of a universal limiting significant wave height (typically 5ft).

In addition to a comprehensive set of analytical results, the main product of Phase 1 of the JIP [11 has been a computer program which enables the user to specify details on rig type, soil type, water depth and wave height and provides guidance on risk to assist in the decision making process. Output is in the form of a table showing the percentage probability of leg overstress for various wave periods and directions.

Phase 2 of the JIP extended the work to examine the safety of jack-ups moving onto location in close proximity to a fixed structure - for example in tender assist or workover modes. This work has considered the likelihood and consequences of an impact between a spudcan and the fixed structure as the rig prepares to touchdown.

This paper briefly summarises those aspects of Phase 1 which have already been published [2,31 and then concentrates on explaining the basis for estimating the risks involved in touchdown operations and presents the results of the work.

OBJECTIVES AND PROCEDURE

In attempting to define a basis for proceeding with touchdown, the main criterion is to ensure that the risk of exceeding the leg structural capacity is not unacceptably high. The approach adopted involved the following aspects:Jack-up motions afloatSeabed-soil characteristicsDynamic impact response (finite element analysis)Leg structural limitationsDetermination of probability of exceedance of allowable leg loads.Development of an analytical computer program, combining all the above aspects and providing estimates of risk.
Troll Sealtubes: Deepwater Innovation In Pipeline Tie-Ins
Authors: Thomson Brian , Kalvenes B.K.
Published: October 2008

The Troll Phase 1 development in the Norwegian sector of the North Sea includes a unique pipeline tie-in system. The field is situated in 303 metres water depth. This has resulted in a system concept which combines the facility of a Gravity Base Structure (GBS) dry riser shaft and a diverless pipeline pull-in method. The system offers a simple and cost effective tie-in method which enables construction of several pipelines within the 1995 season.

The critical interface between the GBS and the pipeline is the SealTube System. The SealTube penetrates the GBS riser shaft wall and provides the conduit for the pipeline pull-in phase.

This paper details the design and the development aspects of the SealTube System.

Introduction

The Troll Gas Field has recoverable gas reserves of approximately 1250 billion cubic metres.

Since the Troll Field was declared commercially viable, more than 80 development concepts have been considered. The production concept adopted for Troll Phase I comprises a platform with limited gas treatment facilities (i.e. free water removed) supported on the worlds tallest GBS; two 36" pipelines for transport of the multiphase gas, to shore an onshore processing plant, and a 40" pipeline for dry gas export to Europe. The platform is located 65 km from the landfall area.

The selection of the GBS recognised the significant track record provided by the Norwegian Offshore Industry in the design and manufacture of concrete structures.

It allows the opportunity to effect a conventional welded pipeline to riser tie-in within a dry riser shaft environment. This removes dependence on expensive deep water welding or connection methodologies. The pre-installation of extra risers and SealTubes also provide back-up for the planned construction and additional pipeline tie-in options for the future. The cost effectiveness of the tie-in system is further enhanced by the removal of diving support requirements from the Marine Support Vessel (MSV) which is utilised to provide construction assistance for GBS preparation and pipeline tie-in phases. Remote Operated Vehicles (ROV's) are utilised from the MSV but primarily for monitoring purposes. The tie-in equipment and subsea packages are designed for deployment from, and remote operation on, the MSV.

The pipeline pull-in operation will be achieved using a platform topside winch which will deliver the pullhead and pipeline into the prepared SealTube. The pull-in cable is run from the SealTube to the winch through an 8" diameter pull tube. The pull tube terminates above sea level thus ensuring the GBS riser shaft can remain dry during the pull-in. The laybarge will lay down the pullhead in a target area then continue to deliver pipe while remaining in a fixed position until the pipeline is pulled inside the SealTube by the winch. The pipeline will then be laid approximately 10km to provide sufficient stability for the SealTube related activities to commence.
Development Of Cost-Effective Diverless Tie-In System For Troll Oil
Authors: Halle P.O.
Published: October 2008

A new type combined pull-in and connection system has been developed for the Troll Oil field Development in the North Sea.

At Troll Oil, satellite wells are spread out in a wide area and tied back to the floating production unit by flexible flowlines and umbilicals via manifolds and a riser base. For the 1st phase of the development more than 120 diverless tie-ins of flowlines and umbilicals are required, 2nd phase will require an additional 150 tie-ins. All pull-in and connection operations will be made diverless at a waterdepth of 325m (1OOO ft).

To perform these tie-in operations in an efficient manner the need for a new tie-in system was required.

The tie-in tool PICT is based on subsea pull-in wire establishment, horizontal pull-in and a hinged clamp connector. The system is made to be flexible related to laying method, installation sequence and reversability. This tie-in system represent a new generation of tools which can be further developed for very deep waters.

This paper present the Troll Oil tie-in system and what considerations were made to make the system optimal related to cost and operability.

Troll Oil Field Development

The Troll field is one of the largest gas fields offshore in the world, located near the west coast of Norway at a depth of 325 m (1000 ft). Below the gas there is a thin oil layer. By using horizontal drilling this oil can be developed. The gas in the field is sold and is under development. To produce the oil the gas pressure is required. Troll Oil project had to be developed fast and with a lot of wells spread out in a wide area.

The subsea production system consists of single well satelites tied back to 6 or 8 slots manifolds with gathering lines via a riser base to a floating production unit (FPU). Between the satelites and the manifolds there are one 6" or 8" flexible flowline and one steel tube integrated service umbilical (ISU). Between the manifold and the FPU there are 2 × 9" or 2 × 10" flexible gathering lines and one main ISU. All gathering lines are connected at the riser base to dynamic risers.

Troll Oil Tie-in System Development Schedule

The design of a combined pull-in and connection tool started back in 1991 based on the experience gained on the Troll Oseberg Gas Injection Project (TOGI). Late 1992 basic engineering studies were performed at Troll Oil for the operator Norsk Hydro as. Summer 1992 the tie-in contract were set out. Testing of the first Pull-in and Connection Tools (PICT) started summer 1993 which were followed up by system testing tie-ins at the Production Riser Base, Manifold Centers and the Sattelites/Permanent Guide Bases. Summer 1994, first tie-in operations offshore will be performed. Production start up of the field is scheduled for january 1st 1996.
Variable-Stroke Drilling Mudpump:: A Concept To Meet Future Requirements
Authors: Figenschou Arild , Haughom P.O.
Published: October 2008

A new generation drilling mud pump has been designed and full scale prototype tested. The test program has confirmed the feasibility of the new concept and the special features.

The pump, which is a piston pump, controls the pumped flow by changing piston stroke rather than speed and therefore eliminates the need for SCR systems.

A membrane prevents the drilling fluid from coming into contact with piston. and cylinder, thus eliminating the liner wear problem.

The pulsation in mud discharge is reduced and at constant frequency independent of flow creates an ideal condition for turbo drills and MWD.

INTRODUCTION

This paper presents design and results from a full scale prototype test of a new generation drilling mud pump made by Tonstad Maskin A/S in Norway.

The new drilling mud pump is the result of five years R&D including one year of full scale testing. The background for the development was the perceived need to eliminate some of the drawbacks of the classical mud pumps, to increase efficiency and reduce downtime.

Typical problems previously encountered were:Liner wearThe need to change liner dia to accommodate pressure / flow rate during drilling operationThe irregular pressure pulsation in the dischargeThe power supply based on SCR controlled DC motorsWeight and space requirements

The fill scale prototype mud pump and a 1000 hours test program were partly financed by Norske Shell A/S, Esso Norge as, Norsk Hydro as, and BP Norge a.s.

DESIGN PHILOSOPHY

The pump is a star configured piston pump with variable stroke. Stepless variation of stroke from zero to maximum. The powering / transmission system is based on AC electric motors running on constant speed. The pistons are working in hydraulic oil. A rubber membrane with equal pressure on each side separates the mud from the hydraulic oil. The mud valves are standard type, but built as a modular system for quick change out and maintenance. Keep dimensions small (max. breadth 3000 mm). Keep the pump and the operation of the pump extremely simple and rugged, with a target of 5000 hours maintenance service free.

DESCRIPTION OF CONCEPT

Basic Principle

The basic operating principle of the pump as shown in figure 1.0 is to have a piston pump with variable smoke. This gives the possibility to run on constant speed whilst controlling the flow. As a consequence of the constant speed, the pump can be directly powered by AC motors. To reduce the liner wear the pistons are working in hydraulic oil. The mud is separated from the hydraulic oil by a membrane in the pump chamber.

The base arrangement of the pump is quite similar to the star configured engines having the crank shaft in center and the cylinders extending radially around the circumference. Two mud pump configurations have been designed, a three piston and a five piston pump.
Offshore Dehydration Of Natural Gas: An Evaluation Of Alternatives
Authors: McKee R.L. , Foral A.J. , Meyer H.S. , Gamez J.P. , Stern S.A.
Published: October 2008

Traditionally dehydration has been a triethylene glycol (TEG) unit utilizing a 4-8 tray absorber with bubble cap trays. These units work well and are relatively inexpensive. However, there has been an increasing concern about hydrocarbons emission from the vent gas and produced water over the last few years. The hydrocarbons of greatest concern are benzene, toluene, ethyl benzene, and xylene (BTEX). Units can be added on to mitigate the emissions but they take up extra space and weight which is expensive offshore. Therefore, there is an increased interest in decreasing the cost and size of conventional units or finding an alternative process that is less expensive. Under Gas Research Institute contract a survey of a number of offshore producers to determine present practices was conducted. Several absorber alternatives and/or modifications for conventional TEG units were compared with a hypothetical membrane unit for dehydration of 75 mmscfd of natural gas at 1000 psia and 100°F. Although commercial membrane units are not yet available a "good" hypothetical unit was compared because of its advantages of simplicity and lack of emissions. The membrane unit, however, was not found to be competitive. A TEG unit with a Higee? absorber was found to have a slight advantage over more conventional trayed and random and structured packing absorbers after taking into account the effect of size and weight as well as initial cost.

SURVEY OF OFFSHORE PRODUCERS

A survey of seventeen offshore producers was performed to generate the following information: (Foral, 1994)Present offshore dehydration practices;Level of industry concern over emissions; andA design basis that would be typical of Gulf of Mexico offshore operating conditions.

Eleven companies responded to the survey indicating that the most commonly employed dehydration process used was TEG dehydration with bubble cap trays. In evaluating alternatives, most respondents reported that savings in size and weight were considered important. The savings in size (footprint) was considered somewhat less important than weight. The level of reliability required for offshore processes was reported by most respondents to be in excess of 95%. Before an alternative process would be considered for offshore use, the consensus of the respondents was that:The unit size should be no larger than existing units with equal performance.There should be a history of successful operation for a period of at least 1-3 years.Materials of construction should be compatible with the offshore environment.

Most of the companies indicated that environmental regulations of the emissions of BTEX and other VOC from offshore sources require research and development to develop new technology.

BASIS OF EVALUATION

Operating Conditions.

The operating conditions chosen for sizing the units were:A flow of 75 mmscfd at 1000 psia and 100°F.The gas was assumed to be methane saturated with water.A fuel gas usage equal to 3.4% of the feed at 135 psia.