bluuebunny/crossref_metadata_2025 huggingface dataset:
Seismic Costs Prediction and Optimization : A Systematic Approach
Authors: Rodriguez Jean-Marc , Pion Jacques , Piazza Jean-Luc , Abdelkader Chaouch
Published: October 2008

Introduction

Budget estimate for seismic projects, whether related to the application for an open exploration permit, to the exploration phase of a permit already awarded or to the appraisal of a discovery or the development of a proven field, are generally requested from geophysicists well ahead of the opening of seismic bids which will reveal the actual costs of the project without ambiguity With the growing application of 3D seismic and its integration with the reservoir development disciplines, the relative weight of seismic expenditures within the total cost of a project has now become a significant item which may affect its overall economic balance Providing reliable and accurate seismic cost estimates and tailoring survey parameters to meet simultaneously technical objectives and budgetary limits have become essential elements of the geophysicists role.

Analysis technique: 3D feasibility study

Within TOTAL, this is achieved by means of 3D seismic feasibility studies which aim at :assessing the economical impact of seismic parameters in order to select the most cost effective 3D field design without compromising data quality nor HSE standards.providing a cost and a duration estimate for the overall project planning purposes. Budget estimates for seismic projects, are generally requested from geophysicists well ahead of the opening of seismic bids which will reveal the actual costs of the project without ambiguity.

We propose a systematic five-step approach:definition of objectives and &ta bases Before initiating a feasibility study, one should ensure that the objectives assigned to the survey are well defined and understood by all the parties involved and in particular by the ultimate customers, the geologists and reservoir engineers. The scope of work ought to clearly specifi the reservoir(s) of interest, the type of information which one expects to retrieve or better constrain using seismic data, the areal extent of the problem. The objectives should be assessed against previous analogue experience. Previously acquired seismic and well data should be inventoried.field reconnaissance The purpose of the field reconnaissance is-to determine the local legal and administrative framework (e.g. customs, radio Iicence, explosive usage, work and safety regulations), the tax regime, the need for additional infrastructure, the logistical (e.g. transport, radio communication, consumables supply, geodetic network), environmental, meteorological constraints, the medical infrastructure (including for emergency medivacs).simulation of basic geometrical designs where bin attributes (i.e. bin offset and azimuth areal distribution) corresponding to a specific design are computed. Details have been published (E. Crouzy, J. Pion, SEG expanded abstracts, 1993 Washington).
The Value of Integrating Existing 3D Seismic into Shallow Gas Studies
Authors: Salisbury R.S. , Geol C. , Denley M.R. , Douglas G.
Published: October 2008

Conventional 3D surveys, although designed and processed with clear exploration objectives in mind, often contain much valuable information in the shallow section This information can add significantly to shallow gas studies based on conventional high resolution seismic techniques. Examples from the North Sea are used to illustrate how an integrated approach to interpretation can lead to a better understanding of the shallow geology and to a more accurate and reliable assessment of drilling hazards, particularly shallow gas. A new approach site investigations has been tried and tested and has been found to be both time and cost effective.

Introduction

In recent years there has been a rapid increase in the use of 3D seismic surveys for exploration and development purposes. Oil and gas producing provinces all over the world are gradually becoming covered by 3D seismic, and the use of 3D in new exploration areas is fast becoming routine. The opportunity exists to make use of these existing datasets in drilling hazard studies of the shallow section. The challenge faced by the seismic interpreters working in this field is how to use this data in the most efficient way.

This paper shows how high resolution 2D seismic. acquired as part of a site survey programme, and existing 3D seismic can be interpreted together to overcome some of difficulties experienced when using either data se[ in isolation. Although the exploration 3D cannot provide the same resolution as high resolution 2D seismic, existing 3D data sets can provide essential information on the shallow geology which can lead ultimately [o a more refined and more reliable assessment of potential hazards, The approach can becaused to assess new with little or no existing high resolution coverage and can also help design site survey programmed. The approach is both time and cost effective.

The paper concentrates on shallow gas, but reference is also made to other tophole drilling hazard.

Conventional Shallow Gas Studies

Shallow gas is one of the most serious hazards offshore engineers face when drilling exploration and development well.

Although not restricted 10the shallow section (top 1000 metres below seabed), it is in this interval where shallow gas, if encountered unexpectedly and without the necessary precautions in place, poses the greatest threat to the drilling operation and the safety of the rig. Incidents vary from costly delays and lost wells to catastrophic blowouts, sometimes involving loss of life.

During the seventies and eighties these incidents occurred with alarming regularity which led to the development of site survey specifically designed to identify potential gas hazards prior to drilling. Site surveys are now carried out routinely to investigate the shallow section and provide essential information on water depths, seabed obstructions, jack-up foundation conditions or anchoring conditions, as well as drilling hazards.
Risk of Foundation Failure of Offshore Jacket Piles
Authors: Horanell M.R. , TooIan F.E.
Published: October 2008

The paper discusses the application of reliability theory to offshore foundation piles. Tire theoretical risk of failure for piles is computed for a range of realistic soil and loading conditions. The reliability analyses are updated in the light of long term field experience and the results used to comment on reassessment procedures for foundations. It is concluded that, if standard design procedures are followed, the outcome is likely to be that, generally, piles in sand are more at risk of failure than piles in clay, and piles governed by the dead load condition more at risk than those for which the extreme environmental load governs.

Introduction

For almost 50 years, the offshore industry has made use of driven piled foundations to support offshore production facilities. Throughout this period, the design of such piles has remained a constant source of attention, especially with regard to the methodology for predicting the ultimate capacity. An account of how offshore pile design procedures have evolved and in particular those of API RP2A is provided in TooIan and Horsnelll and Pelletier et al'.

To date, there have been no recorded incidence in the North Sea of piled foundation failure, with many of the structureshaving experienced their 100 year design storm. McClelland et al.3 in their review of 650 major platforms in the Gulf of Mexico, covering a period of 4000 platform years and seven major storms, including Hurricanes Carla (196 1) and Camille (1969), identified a total of 25 failures, only 3 of which were attributable to soil failure and none to failure of driven piles under axial loading. A more recent study in the aftermath ofHurricane Andrew also indicated that, although there were 150 incidents of damage and failure to platforms, none were attributable to pile failure.

The situation is different under sustained loading where McClelland et al report two cases of failure in clay. If the survey is expanded to include pipe piles for marine structures under test load, then Tomlinson4 and Toolan5 have reported failures in sand at well below design capacity. The results of these testsrequired the piles to be redesigned in order to achieve a satisfactory foundation. In frontier areas, pull-out tests on conductors in calcareous soils have indicated much lower frictional resistance than used in design, leading to remedial measures to platform foundations b. Similar problems are known to occur in micaceous sands.

Failures have been reported of platform piles which have bee; installed by combinations of jetting, drilling and driving. However since there is no agreed design procedure for such, little can be learnt of general application from hindcast studies, other than to proceed with extreme caution if contemplating using such installation techniques. Another category of ‘pile failure’ arises when the pile becomes unserviceable as a structural element during installation. This may be through buckling, tip damage or fatigue during driving.
Foinaven: A Basis of Design for Development Wells
Authors: Howes D. , Cropper M.J. , Prise G.J.
Published: October 2008

The paper provides the Well Engineer/Manager with an overview of the basis of design for Foinaven wells; outlines the contracting strategy adopted forWell Construction; presents a summarized operational programme; and highlights some of the early lessons learned on this fast-track frontierproject.

Introduction

The opening of the West of Shetland oil province presents a new range of challenges and opportunities from those typically encountered in the North Sea. There are a new set of operational problems which have to be faced in a harsh and remote area.

The Foinaven field is located on the flank of the Faroe-Shetland trough approximately 180 km west of the Shetland islands, and 220 km north of the Scottishmainland (see figure I). The field is situated in deep water - the 500m bathymetric contour runs through the field - and in an exposed position on the North Eastern rim of the Atlantic Ocean.

The discovery well on the field, 204/24a-2, was drilled by the Ocean Alliance, in the autumn of 1992. Reservoir evaluation and appraisal was rapid with 6 further wells drilled and an Extended Well Test performed in 1994. As a result of this highly successful production test, project sanction was achieved in October 1994 and development drilling commenced on 9th November 1994.

The objectives of this paper are to provide the Well Engineer/Manager with an overview of the basis ofdesign for Foinaven wells; to outline the contracting strategy adopted for Well Construct ion; to present a summarized operational programme; and to highlight some of the early lessons learned on this fast-track frontier project.

Development Overview

It is planned to develop the field with clusters of subsea production wells producing to and controlled from a Floating Production Storage and Off-loading Vessel (FPSO).

The reservoir measures approximately 16 km by 10 km, and comprises a series of channel sands, running in an east-west direction. The reservoir, which lies 1650 m below seabed, has 3 distinct sand packages which are separated by mudstones. The oil is heavy compared to North Sea crudes (26 ° API), saturated, and sweet. Reservoir pressure is normal (3190 psi 2158 m TVDSS); reservoir temperature is 138 °F. The field has a gas cap, and is attached to an aquifer. Because the individual sand packages are thin (typically 50m TVD), and because the reservoir fluids are of low energy, all production wells arehorizontal, with over 1000 m net producing sand. me net to gross ratio is typically in the region of 60% (Cowper et al., 1995).

The field is extensive in area, and quite shallow. It is being developed from two drilling centres (with a remote gas disposal well), and requires extended reach drilling (ERD) techniques with wells typically having a horizontal displacement to vertical depth ratio of 2.25:1.
The Influence of the Bow Shape of FPSOS on Drift Forces and Green Water
Authors: Buchner Bas
Published: October 2008

In this paper the influence of the bow shape of FPSOS on drift forces and green water loading is studied. Use is made of the results of model tests and diffraction calculations for three different bow shapes: a traditional tanker bow, a sharp alternative bow without flare and the same alternative bow with a significant flare above the still waterline. For the sharper alternative bows the mean wave drift forces and low frequency drift forces seem to be smaller than for a traditional bow. Due to the fact that the wave frequency motions with the alternative bows are larger, it is not clear yet whether the total mooring line loads for this type of vessels will be lower. For the alternative bows the relative motions around the bow are larger. This results in more water on the deck with the alternative bows than with a traditional bow. Also the impact pressures are significantly higher. The results presented in this paper make clear that it is not sensible to optimize a bow of an FPSO on one aspect only,

Introduction

With the trend to bring FPSOS to increasingly harsh environments, the problem of solid green water on the bow becomes an important design aspect. This green water cm cause serious damage to the sensitive equipment or superstructure at the bow, as was experienced with operating FPSOS at the North Sea. There are two ways to cope with this problem: protecting critical structures against green water loading or minimizing the occurrence of green water occurrence and its loading. The achieve the last, the bow shape and bow height of the FPSO can be optimized. Especially for new build FPSOS this is an option, but also for existing tankers optimization are possible].

The effect of the bow shape on the occurrence of green water has been a point of discussion for Naval Architects over a large number of years. Some authors report a decrease in deck wetness when a significant flare is applied3 for traditional ships, whereas others find an increase in deck wetness4 with flare. In Ref. 1 the author presented tests with a traditional FPSO tanker with and without bow flare. It was found that for this particular bow the relative motions increase when flare is applied, whereas the water height on the deck decreases slightly. However, it was concluded at that time that this is not per definition a general trend.

It should also be noted that it is not sensible to optimize the bow shape of FPSOS solely on green water loading. The bow shape can FPSOs effect other aspects of the design, like the (low frequency) drift forces on the ship and the related mooring forces. A bow optimized on green water loading, can may be increase the mooring forces and vice versa. The effect of the bow shape on the added resistance of sailing ships in waves has been studied by Blok5. Detailed published studies on the subject of drift force dependency on the bow shape of moored FPSOS are not known to the author at present.
The Concerns and Benefits of Standardization on the Heidrun Subsea Water Injection System
Authors: Pugh R.R. , Turner R.R.
Published: October 2008

Ms paper describes the process of standarzing the Heidrun Sub sea water injection system. The layout, basis of design and equipment utilized are presented, along with exploring the benefits and concerns of adopting a standard sub sea system. Realized by this approach were: the interchangeability of equipment between Heidrun and other licenses, the lowering of development costs, the capturing of key-lemmings and the sharing of resources. By identifying and weighing the benefits versus the concerns, standardization can be successfully utilized between petroleum companies with different project parameters, thus saving significant costs for all parties.

Introduction

There are marry benefits, concerns, and reward associated with standardizing a sub sea system. In the earlier stages of the Heidrun development, several sub sea concepts were evacuated, ranging from individual water injection wells tied back to the Tension Leg Platform (TLP), to multiple-well sub sea templates.

It was recognized that substantial savings and synergies could be achieved if the Heidrun Project chose art economically viable development concept which fit into Statoil's long-term strategy for sub sea developments (being that Statoil would take over operator ship of the Heidrun field at first-oil). After evaluation, it was decided that the Heidrun Sub sea Water injections System would be modeled after Statoil's Stratford Satellite Project (SSP) design.

However, there were problems. Operating parameters specific to Heidrun, would have to be met. Agreements had to be reached on the use of the existing specialized sub sea tools which were not part of the Heidrun partnership. Finally, capturing the knowledge already hard-won by SSP had to be integrated into Heidrun. This paper describes the Heidrun sub sea water injections system specifics, and shows the process of working through concerns and thereby realizing the benefits of standardization.

Heidrun Subsea Water injection System Description

The Heidrun Field is roughly 10 km long and 6 km wide (figure 1). It is situated on the mid-Norwegian Continental Shelf in an area known as Haltenbanken, 175 km from the Norwegian coast in Production Licenses 095 and 124. The field lies pre-dormis within Block 6507/7 with an eastern extension into Block 6507/8, and in water depths ranging from 310 to 348 meters.

The major reservoirs consist of the Fangst Group, the Upper and Lower Elfie, and the Are Formations, all of Jurassic age. During the planning stages, it was recognized that perimeter sub sea water injection wells would be required to reach the water column in some of the existing fault blocks. The option of extended reach wells from the TLP was explored, but was rejected due to technical difficulties and associated costs. Six water injection we] Is were deemed necessary for optimum, initial water injection and were planned to be drilled from two seabed locations.
The Heidrun Field: TLP Global Performance and Hydrodynamics
Authors: Matten R.B. , Strømsem K.C. , Lassabliere J. , Vogel H.
Published: October 2008

Heidrun, the first deep draft concrete TLP, was installed in July 1995 in a water depth of 345m on the Haltenbank of the Norwegian Continental Shelf. The TLP has a displacement of 290610 tomes and the hull was designed to support a total topsides weight of 64980 tomes on Module Support Beams (MSBS) weighing 18550 tonnes.

The TLP is a marine and structural system with complex interaction between the hull, topsides and the mooring system. This paper describe a the basis for the sizing of the hull and tether system. Key issues addressed include weight control, stability during installation, tether system loads and constraints from fabrication and installation. The relative merits of the use of concrete rather than steel for the hull construction are discussed from a hydrodynamic perspective.

Hydrodynamic model testing was used to resolve many critical design issues, including 'ringing' which has had significant consequences for other deep water offshore platforms. New criteria were established for tether pretension.

The Operational Expense of TLP Marine Control has been minimized by provision of the Marine Control and Data Acquisition system (MCDA), which is used for in-service control of tether tension and for acquisition of key environmental and performance data. Continuity of weight control during Engineering, Construction, Installation and Operation was successfully implemented. TLP Performance data is presented in sea states up to 10.5m significant.

Evaluation' by the Conoco Project Team of TLP performance, on-board training of Operators and provision of an automatic system for continuous shore-base monitoring of marine performance facilitated the timely handover of responsibility for TLP Marine Control to Statoil Operations.

Introduction

Early conceptual studies [1, 2] identified several advantages of the concrete hull which were key in concept selection. These include elimination of fatigue concerns at complex node intersections, high distance to impact loads, relatively simple and faster construction, low sensitivity to increases in topside a weight and low tether design loads.

Preliminary Engineering Contracts were awarded to two competing Contractors in February 1991 for development of a concrete hull TLP for the Heidrun Field Development. The Engineering, Procurement, Construction and Installation (EPCI) contract was awarded to Norwegian Contractors (NC) in December91. Following wind tunnel testing of the topsides in November91, the NC concept was model tested in January 1992 in order to accommodate the design freeze scheduled for the end of March 92.

Unexpectedly high loads were measured in the tether system due to 'ringing', the term given to the global vibration of the TLP at it a natural period in pitch and roll, coined during the model testing of the Hutton TLP in 1979-80. Ringing was previously considered for steel TLPs to be a minor load effect and its cause had never been clearly identified.
The Heidrun Field - Heidrun TLP Tether System
Authors: Hornung M.R. , Hanna S.Y. , Hannus H. , Rowan D.
Published: October 2008

The Heidrun TLP was installed in July, 1995. The tether system was developed to meet the following requirements preinstall the tether strings before platform installation; commission the tether tension monitoring system before platform tow to field; lock-off on all sixteen tethers simultaneously 50-year platform design life inspection, maintenance, and repair capability over the operating life. The system and component designs, operations trials, and experience to date are summarized.

INTRODUCTION

This paper presents a brief description of the Heidrun tether system, which anchors the platform to the seabed foundations. The overall system is shown in Figure 1. A description of thefunctional requirements for both present and installation phases provides the background for the system configuration.

The global platform response gives the performance requirements. As the Heidrun platform differs considerably from previous tension leg platforms, a number of challenges had to be faced. The main ones related to loads, installation and schedule.

The tether system was divided into component assemblies or packages, bawd on logical interfaces and contractor capabilities. An outline of the assembled unit is given in Figure 2. The features of the component assemblies are described next. The main packages are the bottom connector assembly, the flex element, the tether string, the top connector assembly, the installation equipment, the tether tension monitoring system and the tether inspection system.

As part of the system design, the main components were subject to prototype testing. In addition, trials of the inspection maintenance, and repair equipment were performed onboard the platform before the tow to field. Further, the installation equipment was tested and the full installation crew was trained on board before low.

The paper is concluded by the main experiences from implementing the chosen solutions.

SYSTEM CONFIGURATION

From experience gained during earlier tether system work, it was apparent that development of the Heidrun tether system should simultaneously consider both temporary and permanent phases when defining system requirements. Thus, a systematic approach was applied which brought together consideration of in-place operation, installation, fabrication, and integration inter facing with the platform's substructure and foundations.

During the course of preliminary engineering in 1991, the Heidrun tether system's overall configuration was therefore development in parallel with the development of the marine operations required for installation of the tethers and platform. From the beginning of this work it had been assumed that thetethers would be of single-piece, neutrally-buoyant design. Other options such as the use of connectors and welding in-situ were investigated but the single-piece welded system was the most economic concept for this environment.
Rocky Flowline Project - The Gulf of Mexico's First Reeled Pipe-in-Pipe
Authors: Hoose J.W. , Schneider D.R. , Cook E.L.
Published: October 2008

The paper reviews the Rocky Flowline project from preliminary design through detail design, testing, fabrication, and installation, The emphasis of the paper is on the issues involved with deep water insulated flowlines, with special emphasis on fabricating and reeling insulated pipe-in-pipe flowlirres. The paper highlights the design and installation of 21,000 ft of dual insulated 3-inch inside 6-inch flowlines in water depths up to 1785 feet. The paper and project is of significance to those in the industry involved in deep water oil development and the transportation of waxy crudes.

Project Overview

The Rocky Prospect is located in 1785 f=t of water in Green Canyon Block 110 (Figure 1). It is being developed by a single subsea oil well tied back approximately four miles to the Green Canyon 65A (Bullwinkle) platform by two nominal three inchflowlines of pipe-in-pipe construction till-rated for the design shut in tubing pressure of 7200 psig. A strong water chive is expected resulting in production rates of up to 8000 BOPD

The well was drilled, cased and temporarily abandoned in Second Quarter 1995. The flowlines were installed in July 1995 by the reeling method. The flowlines were laid horn GC 65A towards the well where they were terminated on a common sled which was placed a short distance from the wellhead, Completion of the well and the installation of the subsea hardware began in December 1995 and first production occurred in January 1996. Flexible pipe jumpers installed by the completion rig connect the subsea tree to the sled.

The subsea tree is an API 10,000 psi design with a single master valve and a piloted hydraulic control system. A thermoplastic hose umbilical connects the well to a hydraulic control panel located on GC 65A. The umbilical includes conduits for the hydraulic control functions and chemical injection, as well as electrical cables for pressured temperature date transmission back to GC 65A. Facilities are provided to allow paraffin inhibitor to be injected downhole and methanol to be injected at the tree if required for hydrate inhibition.

The dual flowlines allow periodic round trip pigging from the platform via a pigging loop on the Gee. The well can be configured to flow through either one or both of the flowlines, A surface choke at GC 65A is used to control the flow rate. In the event of an extended shutdown, the flowlines are displaced with dead oil to prevent hydrate formation.

Preliminary Design

In order to mitigate paraffin and hydrate concerns it was deem necessary to minimize heat loss in the flowlines keeping the platform arrival temperature above the anticipated crude oil cloud point of 90 degrees Fahrenheit. Preliminary analysis indicated that externally applied insulations could not meet this design criteria. Flowline bundle and pipe-in-pipe designs each were capable of meeting the heat retention criteria and were both investigated further.
Seismic Hazard Evaluation of the Oman India Pipeline
Authors: Campbell K.W. , Thenhaus P.C. , Mullee J.E. , Preston R.
Published: October 2008

The proposed Oman India pipeline will traverse approximately 1135 km of the northern Arabian Sea floor and adjacent continental shelves at depths of over 3 km on its route from Ra's al Jifan, Oman, to Rapar Gadhwali, India. The western part of the route crosses active faults that form the transform boundary between the Arabian and Indian tectonic plates. The eastern terminus of the route lies in the vicinity of the great (M - 8) 1819 Kutch, India, earthquake. A probabilistic seismic hazard analysis was used to estimate the values of peak ground acceleration (PGA) with return periods of 200, 500 and 1000 years at selected locations along the pipeline route and the submarine Indus Canyon?a possible source oflarge turbidity flows. The results defined that the ground shaking hazard along the pipeline route and Indus Canyon for evaluation of risks to the pipeline from potential earthquake induced geologic hazards such as liquefaction, slope instability, and turbidity flows.

Introduction

The Oman India pipeline is the most technically challenging offshore pipeline project in history. Its inaccessibility makes it essential that potential earthquake hazards such as ground shaking, slope instability, liquefaction, and turbidity flows be Bthoroughly understood and mitigated. This study addresses the ground-shaking hazard. The results of this study will be used by others to address the geologic hazards.

Pipeline Route. The proposed submarine pipeline originates at Ra's al Jifan on the east coast of Oman and terminates at Rapar Gadhwali on the northern coast of the Gulf of Kutch, India (Fig. I). The total length of the pipeline route is approximately 1135 km. Offshore Ra's al Jifan, the pipeline route traverses the relatively narrow Omani continental shelf, crossing the Siquirah fault and descending the steep continental slope to a depth of 800 m. The route then proceeds in a southeasterly direction towards the Owen Fracture Zone- Murray Ridge Complex, descending to a depth of more than 3000 m. Within this complex, the pipeline route crosses the northern segment of the Owen Fracture Zone and the southern extension of the Dalrymple Trough.

From the Murray Ridge Complex, the route continues in an easterly direction and descends onto the Arabian Sea Abyssal Plain and the Indus Fan where it achieves a maximum depth of 3500 m. Several hundred kilometers from the India coast near 66'E, the route turns towards the northeast, crossing several major submarine channels that are incised into the Indus Fan. As it approaches the coast of India, the pipeline route undergoes a steep rise to a depth of 200 m and traverses 140 km of gently sloping continental shelf to its terminus at Rapar Gadhwali.

Seismic Hazard Analysis Methodology

Ground-shaking hazard was quantified of peak ground acceleration (PGA). Specific seismic design criteria have not been established for the pipeline. In lieu of specified criteria, values of PGA were estimated for return periods of 200, 500 and 1000 years.
Fatigue of Mooring Chain in Air and Water - Results and Analysis
Authors: Stiff John J. , Smith David W. , Casey Neil F.
Published: October 2008

The paper will present the results of the joint industry study into the fatigue resistance of large diameter anchor chain', and discuss the interpretation of the results. The study represents the largest body of well documented corrosion fatigue tests on a variety of different chain grades and sizes. The analysis & the results use the available fatigue data, including the life of tested but un-failed Iinks, to determine suitable fatigue curves for mooring lines of different lengths. Many of the findings were to be expected, based on past data, but there were some surprises with respect to chain grade. Fracture surface examination indicate that the fatigue cracks had propagated across a large percentage of the section prior to final tire. Post test inspection of un-failed links indicate that many cracks had initiated prior to failure.

Introduction

In 1989 Noble, Denton and Associates, Inc. (NDAI) launched a joint industry study into the fatigue of mooring anchor chain. At the time there was very little fatigue data available, and almost no consistent sets of data comparing different parametersat realistic mean loads and dynamic load ranges.

The main study reached completion in December 1992 when National Engineering Laboratory (N EL) completed as much of the test program as they could within the budget provided.

The program consisted of sets of air and water fatigue tests. All of the air tests, and two of the corrosion tests were carried out in a 'Pre-Test' program. This was set up to determine priorities for the main test program performed at O.7Hz, except for two performed at 0.2 Hz. The main test The sea water tests were benchmark tests that were program entailed only sea water tests. In total, there were seven air tests and nine sea water tests, producing 49 fatigue failures and 66 test run out

It appeared from the last test of the main test program that there was a disproportionately low life for the 4' K4, in water, which had not been expected based on the results of the pretest program. In the pre-test program, conducted in air, it appeared that it would be reasonable to plot the fatigue life of K4 on the same Iine as ORQ chain, but using K4 break in strength. (This is contrary to what is said in API RP 2FP12, which was, it was assumed, being conservative because of a lack of data.) By contrast, the corrosion fatigue test results from the main program suggest that the fatigue life of K4 is at the 'lower end' when it is plotted with respect to ORQ chain breaking strength. For this reason, it was suggested that additional tests be run on 3' and 4' K4 chain, The extension study entailed a further four corrosion fatigue tests.
Design and Installation of Suction Anchor Piles at a Soft Clay Site in the Gulf of Guinea
Authors: Colliat J.-L. , Boisard P. , Gramet J.-C. , Sparrevik P.
Published: October 2008

Innovative shallow suction anchor piles have been used for permanent mooring of a process and accommodation barge at an oil and gas field developed by ELF Congo in the Gulf of Guinea. The 12 mooring lines, equipped with 5m diameter and 13m high steel suction anchor piles, were successfully installed at the site in July/August 1995. The process barge is scheduled to be connected early 1996 for start of production. With a water depth of about 170m, the Nkossa field is the deepest in offshore Western Africa to date. The soils at the site consist of soft normally consolidated clays, representative of deep water sites. The anchoring system design is presented, together with the description of the suction pile installation by under pressure. The monitored performance of the suction piles during installation is evaluated, including orientation and tilt at touch-down, and penetration rate during suction penetration. The installation behaviour appeared to be very smooth, and the measured penetration resistances were in perfect agreement with the predictions, thus demonstrating the reliability of the design installation method.

Introduction

The suction anchor piles, penetrating into the seabed by means of creating an under pressure by pumping out the water entrapped inside the caisson, are found as 'buckets', 'skirted foundations' or 'suction anchor piles' in the literature. The principle was first introduced by Senpere and Auvergne (Ref. 1), as alternative anchor for mooring a storage tanker at the Germ field offshore Denmark. More recently, and because of its and reliability, this foundation concept has renewed interest in the offshore industry, simplicity found a both as foundation for fixed platforms and as mooring anchor point. In addition to the Germ tanker mentioned above, mooring systems with suction anchor piles have been installed at three different sites in the course of the summer 1995, at Harding and Yme fields in the North Sea, and at Nkossa field offshore Congo.

The Nkossa oil and gas field presently developed by ELF Congo is the deepest field in the Gulf of Guinea to date, with a water depth ranging between 150 and 300m. It includes two steel jackets (installed early 1995) with tender-assisted drilling, one process and accommodation barge (scheduled to be at the site early 1996 for start of production), and two floating storage and offloading tankers, one for oil and one for LPG (see Figs. 1 and 2).

The design of the anchoring system for the process is given in the paper, together with the description of the suction anchor pile installation, with an emphasis on the monitored performance of the suction piles during installation.

Barge and Site Characteristics

Process Barge, The process and accommodation barge to be installed at the Nkossa field is presently under hookup and commissioning in South of France, near Marseilles. The hull, 220m long, 46m wide and 16m deep, was built by Bouygues Offshore in high performance pre-stressed concrete.
Sour Gas Dehydration in Mobile Bay
Authors: Betts F.C. , Lay A.G.
Published: October 2008

An evaluation of Mobil's different methods of sour gas development utilized offshore and processes selected are presented with the maintenance history. The conclusions are based on field data showing past performance with a correlation made for future development and the selection criteria for dehydration

Introduction

Mobil's offshore operation in Alabama is divided into two main fields: The Lower Mobile Bay-Mary Ann Field and the Mobile OCS Block 823 Field.

The Mary Ann Field was the first Alabama offshore production and started in April of 1988. Located in state waters, the field spans the entrance and shipping channels 01Mobile Bay. The original field consisted of four producing wells, three production platforms and one auxiliary platform which served as a pipeline gathering facility.

The Mobile 823 Field is located southwest of Mobile Bay and south of Dauphin Island. This was the first production from OCS waters offshore Alabama and occurred during September 1991.

These fields have been designed, constructed, and produced independent of each other due to the gascompositions, rates, and timing. The average hydrogen sulfide content of the Mary Ann field is approximately 5 mol% while that of the Mobile 823 field is considerably less at approximately 150 ppm. Bottom hole pressures and temperatures of the wells differ with the higher values associated with the Mobile 823 field. Different methods for development have been chosen based on philosophy, operational requirements, and information which were available at that time. Now with the information and knowledge gained, all future production must go through a rigorous evaluation for the most cost effective method to produce and which system to incorporate that production.

Design Philosophy

The design philosophy for the Mary Ann field was based on the technologies available for that time period. The final design incorporated the cooling, separation and dehydration of the sow gas offshore to allow for the use of carbon steel materials for the surface and pipeline components. A corrosion inhibition system was also incorporated in the design to protect the carbon steel equipment upstream of the dehydration system and also to solubilize any element sulphur deposition which might occur on the platform.

Both glycol and desiccants were evaluated for sour gas dehydration with silica gel being chosen as the final design philosophy. The silica gel was chosen over other desiccants due to lower regeneration temperatures, less coking, and little or no carbonyl sulphide(COS) formation. The carbonyl sulphide formation had little to no affect for offshore, however this would have increased the sweetening unit load, the sulfur recovery unit, and the tail gas treater at the onshore plant. Some disadvantages noted of silica gel were the need for a regeneration media and the mechanical switching valves required for the cyclic service. Each of these added to the complexity of the desiccant operation and maintenance requirements.
Design, Construction, and Use of a Coiled Tubing Drilling Structure for Onshore and Offshore Operations
Authors: Frishmuth R.E. , Pursell J.C. , Middleton R.J. , Parker C.O.
Published: October 2008

This paper discusses the design, construction, and Initial application of a structure for supporting a coiled tubing injector head, bottom hole drilling assembly and pressurized lubricator. The paper includes a discussion of the features desired for the structure and how these were addressed during the design. The manufacturing of the support tower and its support platform are then discussed. On site assembly procedures for the movable structure are presented along with photographs of the deployed rig in service. The versatility and usefulness of the structure are discussed from the end users point of view.

Introduction

In early 1994, during planning for an effort to explore using coiled tubing for drilling operations, the engineers working on the development realized that a structure would be needed to support the weight of the drilling equipment. The objective of the drilling operation was to enter existing wells through the swab valve on the top of the Christmas tree and, while under pressure and blowout prevent (BOP) control, drill laterals into new pay zones. Hence, the BOP was to be mounted on top of the Christmas tree along with a lubricator long enough to contain the entire bottom hole assembly (BHA) and strong enough to contain well pressure. The coiled tubing injector head and pack off would need to be mounted on the upper end of the lubricator. The mechanics of this operation requires that long and heavy pieces of equipment would have to be held vertically over the well with the coiled tubing injector head located at the very top of the equipment stack. It was recognized that a unique and portable structure was needed to hold the coiled tubing drilling equipment. Thus, CAMCO, with the agreement of British Petroleum, a major partner in the drilling project, began a program to design and construct a support tower and a platform on which to locate the tower. This paper is a report on the various phases of the design, construction, and deployment of the drilling structure (DS).

Design Requirements

The primary purpose of the DS is to prevent bending moments and undue compressive loads from being transmitted to the wellhead while permitting the entire BHA to be lubricated above the wellhead and BOP's. This required that the tower had to be rigid enough to prevent the injector head from moving relative to the wellhead, even under the loads imposed by the down hole coiled tubing weight and the side pull of the coiled tubing reel. Further, the compressive loads from all downward forces had to be eliminated from the long lubricator to prevent buckling. The meant that the downward and overturning forces had to be carried through the tower, into a platform, then via platform supports, to the ground.
Solutions and Procedures to Assure the Flow in Deepwater Conditions
Authors: Gomes M.G.F.M. , Pemirs F.B. , Line A.C.F.
Published: October 2008

Petrobras has been developing deep water oil fields located in Campos Basin a vanguard subsea project which faces big challenges, one of them wax deposition in production flowlines. So, since 1990, Petrobras has been studying methods 10prevent and remove paraffin-way deposits. Tests of techniques based on chemical inhibition of crystal growth thermo-chemical cleaning (SGN), mechanical cleaning (pigging), electrical heating and thermal insulation were done and the main results obtained at CENPES (Petrobras R & D Center) started to be used in the field in 1993.

This paper presents solutions and procedures which has been used to minimize oil production losses at Campos Basin - Brazil.

Introduction

The occurence of different types of deposits on pipelines, which affect operational routine in offshore installations, leaded Petrobras to deal with this problem.

In order to evaluate the available methods for preventing and removing these deposits and develop others, the Program on Deepwater Exploitation Systems (PROCAP 2000) has been studying and testing many techniques. Special attention has ken driven to wax prevention and removal methods, for this. is one of the main operational problems faced up.

From the beginning of first phase of Albaccora field exploitation in 1989, it has been noticed that some production flow lines presents organic deposits build-up. This phenomenon happens when paraffin comes out of solution, as the oil reaches the WAP (Wax Appearance Point), due to low sea bottom temperatures.

Although Petrobras is aware about asphaltene, scale and hydrate occurrence, this paper will focus on wax deposition problems, and present difficulties, solutions, procedures adopted by Petrobras in minimizing wax deposit impact on deep water exploitation projects. The use of these techniques imply in additional investment that must be foreseen in the initial phase of the project.

The following aspects will be highlighted:How to predict the wax depositionHow to solve the problemProject implications on the development of oil field where wax deposit has been foreseen.The development of Albaccora, Marlim and Barracuda fields.

PROCAP 2000 - Flow Assurance in Deepwater Conditions Project

PROCAP-2000 is The Petrobras Program on Deepwater Exploitation Systems. The aim of this technological innovation program is the reduction in production costs, increasing productivity in deepwater fields and enabling oil production at water depths over 1000 meters. Production losses due to organic deposition in the flow lines of the wells located far from the production platform can be avoided through studies on the deposition phenomena and establishment of feasible operational techniques. The Flow Assurance in DeepwaterConditions is one of 12 projects included in the scope of PROCAP-2000. (see figure - I)
Measurement of Break Away Yield Stress of Waxy Crude Oil and Pipeline Restart System Design
Authors: Williams T.M. , Hsu J.J.C. , Patterson H.L.
Published: October 2008

Break Away Yield Stress (BAYS) has been measured on waxy crude oil from the South China Sea to help develop appropriate design specifications for the HZ production system. Design of subsea production systems for handling relatively high BA KS crude oils will be discussed. A BAYS measurement system for measuring the live and dead oils at various cooling rates and the effect of cooling rate on BAYS will also be discussed.

The measured BAYS of the HZ crude at seabed temperature indicated that reproduction was interrupted and the crude in the pipe line cooled to seabed temperature, the restart pressure would exceed the pressure rating of the originally planned pipeline. For way crude with high yield stress at seawater temperature, the production system must be designed to allow the production to be restarted after unplanned shutdowns.

BAYS of the oil can affect the economics of a crude production system. Accurate knowledge of the BAYS will al[o w optimum spacing of emergency clean out ports or other system modifications that may be considered for an optimum restart system design

Introduction

The crude oil produced in many fields has a pour point above the ambient temperatures that the crude oil may encounter. During normal production, the oil temperature may remain above the pour point. However during shutdowns, the oil may cool to below the pour point and gel. If the shutdown continues, the BAYS of the oil may continue to increase even after the oil gels. The pressure required to restart flow may exceed the pressure rating of the pump or the pipeline.

Accurate measurement of the BAYS of many waxy crude oils are needed so informed decisions can be made during system design and while developing procedures to be followed so production can be restarted planned and unplanned shut downs.

We have designed a system to measure the BAYS of stock tank and live crude oils at selected temperatures. The cooling rate of the oil can be controlled and measurement of the BAYS at the selected temperature can be delayed to best model field conditions.

Discussion

To measure the BAYS of an oil is fairly simple. Just cool an oil sample in a pipe to the desired temperature and measure the amount of pressure it takes to push the oil from the pipe. However, to obtain a measurement that is sufficiently accurate to be useful in planning a production system, several things must be considered. Some things to consider are:Cooling rate of the oil,Pipe material,Temperature, andLength of time atler cooling before measurement is made.

If the yield stress of live oil is to be determined, the measurement system must be designed to contain the live oil at a high enough temperature to melt all wax particles and to be filled without contaminating the oil. The system we have been constructed is discussed below.