bluuebunny/crossref_metadata_2025 huggingface dataset:
Smedvig Production Unit 380- A New Concept
Authors: Nergaard Arnfinn , Lenning Ketil , Levett Chris
Published: October 2008

This paper describes the development of the Smedvig Production Unit (SPU) 380, a new FPSO (Floating Production, Storage and Offloading) concept.

The paper outlines how a market analysis was combined with a business strategy to arrive at a certain set of design parameters and capacities.

With this as input the project team prepared an Outline Specification for a fully integrated production vessel. The Outline specification further termed the input for the Basic Engineering work. Within a time frame of 13 months the project was brought from an idea to the actual ordering of the first SPU 380.

Introduction

The industry is presently witnessing a remarkable boost in the interest for Mobile Production Systems. Mobile Production Systems are either monohull FPSOS (Floating Production Storage and Offloading), semisubmersible FPVS (Floating Production Vessels) or JUPVS (Jack-up Production Vessels).

The increased interest for FPSOS was particularly seen in 1994 when a number of vessels was ordered by oil companies and contractors. Through 1993 and 1994 several designs were developed of which a certain number of purposebuih FPSOS are now about to be realized for start-up of operations in 1996 and I997.

One of the concept designs that was developed during this period was the Smedvig Production Unit (SPU) 380, a medium size FPSO capable of storing 380,000 bbls of crude oil and with a nominal production capacity of 50,000 bbls of oil per day. Ref.

Fig. 1- SPU 380 Artistic Impression.

This paper describes tbe 13-month development of the SPU 380, starting in March of 1993 and ending in April of 1994 when the first SPU 380 was ordered from Far East Livingston Shipbuilding in Singapore.

Market Analysis -1 month

The FPSO as a concept has generally developed from the need to find viable solutions for development of the smaller fields, say for recoverable reserves of less than 50 mill. bbls.

Over the last 15 to 20 years the industry has seen a number of tanker conversions adapted to meet the criteria of small fields. In general the project model has been for oil companies to buy a second-hand tanker, convert it and produce the field for a certain number of years. The average production life time has been in the range of 3 to 7 years. Although some of the vessels have been redeployed for a second production application they have normally been planned for one specific field application only.

Over the last 10 years contractors have seen this as aninteresting business opportunity. One vessel might be designed with sufficient flexibility to serve a number of the smaller fields, The business strategy is then for the contractor to own and operate the vessels and thus offer a service rather than the facilities as such.
FPSO's Fulfilling Shelf Requirements by the Maritime Approach
Authors: Baunan T.
Published: October 2008

Purpose-built FPSOS have at present gained a position by operators as a viable and technically fully acceptable solution compared with the cautious attitude experienced only a few years ago.

During these years we have also seen that the majority of the FPSO's have been contracted to traditional shipbuilders for construction.

The transition from the typical ?fixed offshore platform' environment to the ?floating offshore installation' environment of marine builders (i.e. shipyards) has posed quite a few challenges to all involved parties.

The role of offshore legislators and their adaptation to the new players. i.e. yards, vendors, ship owners as well as Marine Administrations and Classification Societies have and will continue [o undergo changes to adjust to the offshore industry which extends way beyond the mobile drilling unit practice.

However, the tradition and the practical approach of the maritime industry can be satisfactory mated with fixed offshore practice contingent that the two cultures are willing to appreciate the best of the other. Among the challenges to be taken in this respect, the most important task is for the marine industry to take and exercise a dedicated ownership of the philosophy and principles of risk based design and implement it throughout all stages of an offshore project.

1. INTRODUCTION

FPSO's, or Floating Production. Storage and Offloading Vessels, are by no means a new concept nor unproved, but the North Sea Continental Shelves have not been folly aquatined with these until the recent years.

Tankers for oil and a few column stabilised units have been converted into FPSO/ FSO / FPU'S for operation in Brazilian and Asian waters the last two decades and proven to suit the demands set forward by the operators, The UK Continental Shelf (UKCS) has also seen an increased volume of converted tonnage enter into FPSO service in harsh environments, but it was not before the entrance of the Petrojari 1, a purpose built new production, storage and offloading ship. that FPSO's attracted serious attention from major Norwegian operators. However, it took another two FPSO new buildings initiated on a speculative basis by Norwegian ship owners before the concept of FPSO's gained the present dominant position in the North Sea region.

In regions outside the North Sea, converted tankers or semi's are still the preferred option, although a few new built FPSO's have entered into service in Asian and Australian waters.

The transition from the typical ?fixed offshore platform' environment with a network of well established offshore fabricators, engineering companies and vendors 10 the ?floating offshore installation' environment comprising of marine builders (e.g. shipyards) with their network. has posed quite a few challenges.
Turret Mooring System Design and Analysisfor Harsh Environments
Authors: Huang Ken , Judge Sandra
Published: October 2008

This paper discusses key factors that must be considered in the design and analysis of internal turret mooring systems for ship-shaped FPSO vessels in harsh environments. Peculiarities of this type of mooring system, such as extreme sensitivity to non-collinear environments, excessive vertical motions at the fairlead, and complicated thruster control strategies, require that design and analysis of the mooring system be closely interrelated to other subsystems such as turret and riser systems, as well as to the vessel itself. In addition, the selection of the mooring design code that will be followed can have a significant impact on the final mooring line tensions derived and it is important to understand the types of analytical approaches that can be used as well as their limitations when applied to turret moored vessels. Model testing, especially for turret moored FPSOS, can prove particularly beneficial if properly planned. With advance knowledge and understanding of the possible implications of all these factors, trade-offs in the design can be properly evaluated.

Introduction

In recent years Floating Production, FPSO mooring system Storage and Offloading (FPSO) systems have &en gaining popularity due to the cost effectiveness of developing marginal fields with expected production lives of less than 10 years. ?Ilk is especially true when these fields are located in remote areas lacking the support of infrastructures such as existing pipeline networks. One type of application that is becoming more prevalent is the internal turret moored FPSO tanker. As these vessels move into deeper waters with harsh environments, the design of their subsystems, including moorings, turrets, and risers, becomes critical. These three key subsystems are interrelated. The riser design will determine the vessel offset criteria for the mooring system design. The mooring line loads have to be transferred to the turret for structural strength analyses. The turret location will affect not only the weathervaning capability of the vessel, but also the dynamic loads on the mooring lines due to the vertical motions at the fairlead The turret design may place restrictions on the number of mooring lines allowed, and the layout of the mooring lines may pose interference concerns for the risers, It is important to understand how these subsystems are related, and why many aspects of the design or analysis of the mooring system for a turret moored FPSO must be carefully approached.

Other important considerations for turret moored FPSOS, particularly in harsh environments, are the selection of the mooring analysis procedures and the design cede. Theenvironmental loads on the vessel, the motions of the vessel, and ultimately the mooring line tensions are all impacted by the type of analysis performed and details of the code requirements. The mooring analysis procedure generally followed today for turret moored vessels were developed for more conventional semisubmersible-type mooring systems, and the resulting limitations should be understood.
The Hydrodynamic Model Testing for Closed Loop DP Assisted Mooring
Authors: Aalbers A.B. , Merchant A.A.
Published: October 2008

Far East Livingston Shipbuilding (FELS) is presently completing the construction of the Smedvig Production Unit SPU 380, which will be operated as FPSO for Esso BALDER Field Offshore Norway.

In good cooperation with FELS and ND&A Inc. of Houston an extensive model test program was carried out for approval and optimization of the DP assisted mooring system. The main aspects were:Investigate the performance of the mooring in two water depths, i.e. 250 m and 70 m.optimization of DP control for the three azimuthing thrusters.Measurement of motions and wave induced loads at e.g the bilge keels, keel and deckhouse front.Determination of limit sea state for turning the vessel around against the weather.

The tests were carried out in the Wave and Current Basin of MARIN, using a closed loop DP control system to steer the thrusters.

The paper presents the findings with respect to the effect of DP control strategy on mooring loads and present selected results of wave induced loads on bilge keels and deck house.

Introduction

In 1994, the SPU 380 construction was started on speculation. Therefore the model test investigation of its mooring covered a range of water depths. The main dimensions of the vessel are given in Table 1. II is an FPSO concept with a drag chain turret located at about 30 m forward of the midships, see Fig. 1. Nowadays, turret mooring concepts are considered the most economicalSPM systems, since the reliability of high pressure flexible risers has been proved and the technology of catenary moorings has developed to high standards of refinement with the use of composite mooring arrangements. Basically, two mooring concepts are in the market: passive moored and DP assisted moored F(P)SO'S. The passive systems stem from a past of single point moorings withfully rotatable fluid swivels e.g on the Tazerka (SALS, 1982) and Central North Sea (1996) FPSO'S, The DP assisted concepts were developments from drillship technology through e.g. the Petrojarl vessel in 1986 [o the Gryphon A FPSO in 1993.

In DP assisted mooring on a drag chain turret, as for the SPU 380, jumper hoses are used instead of a continuous multistack fluid swivel. The presence of the DP system allows to turn the vessel in moderate sea conditions to uncoil the jumper hoses. The deckhouse is placed at the bow, upwind of the process area and turret area. Due 10 the heading control that can be exerted by the thrusters, the permanent mooring on a turret located relatively far aft the bow is feasible, see e.g Ref. [1].

For the SPU 380 the mooring consisted basically of a 92 mm (3.75'), 10 leg chain system, connected to winches and running out through fairleads below the keel of the turret.
Atlantic Alliance: The Next Generation Tension Leg Platform
Authors: Logan B.L. , Naylor S. , Munkejord T. , Nygaard C.
Published: October 2008

Since 1990, the technical and commercial environment in the oil and gas industry in the U.K, has seen a step change in relationships. This has contributed to significantly improved development cost and time parameters. By harnessing the potential energy and expertise in the market place, many more marginal fields are now below brought into production. This paper gives an insight into the exceptional results that can be achieved by bringing together complementary skills and expertise, having a common vision for the future.

Introduction

The Atlantic Alliance (AA) is a joint venture formed by the AMEC and Iaing groups from the U.K. and the Aker group from Norway. AA came together in late 1994 for BP's prequalification process for deepwater solutions for the UK North Sea and Atlantic waters. 1 Msprocess resulted in AA being rated as 'best in class' by BP for a concrete tension leg platform, AA were then invited to participate in a design competition against other consortia with alternative solutions, for the second West of Shetlands development known as Atlantic Frontier Programme II (AFP II). The AA proposals were based on a down scafed version of the first concrete TLP by Aker for Conoco's Heidrun field in Norway. A step changein costs and schedule were achieved but not sufficiently to win the project.

BP and AA however, felt that the relatively short bidding period had not given enough time to fully release the potential of the concrete TLP solution. A joint workshop and subsequent study brought together a selection of key individuals with Gulf of Mexico, Norwegian and U.K. related experience to explore options to radically reduce time and cost parameters. By Christmas 1995 this study work had delivered the potential for a major breakthrough for the next generation TLP. At the time of writing, this is now moving into the full concept development phase ready for its first project.

Study Process and Result

Expectation For the TLP to be retained in the development matrix as a concept of opportunity, a step change in competitiveness (versus the FPSO) must be realised. Expectations were that through this work, a concept would be defined that will realise the requisite level of step change througha CAPEX reduction of 25% from AFP IIa delivery programme reduction from commitment to 24 months from the AFP II schedule of 30 months, i.e. 20%,an installation window that is not seasonably limited, i.e. similar to a FPSO

Result The study work delivered a step change opportunity. The New Generation TLP has taken us beyond our expectations with:an estimated 30% reduction in CAPEX,a sub 24 month programme from commitment anda weather window of 12 months - in line with an FPSO.
Precise Target Prediction From 3-D Seismic Data: Case Histories From the Gulf of Mexico
Authors: Duncan Peter M. , Nester Douglas C.
Published: October 2008

Modern 3-D seismic datasets provide information about the subsurface that goes well beyond the accurate mapping of complex structures. Utilizing attribute analysis of reflection character, it is often possible to peer inside the structure to estimate reservoir quality and fluid content. Carefulapplication of this analysis will lead to more precise prediction of what the drill bit will find and therefore allow the confidence to drill smaller hydrocarbon accumulations.

This paper will illustrate such analysis on two prospects in the Gulf of Mexico. In both cases attribute analysis of 3-D data was successfully used to predict the presence or absence of hydrocarbons in specific reservoir intervals with a high degree of precision.

Introduction

The burden of experience now firmly establishes the importance of 3-D seismic, The first and most obvious benefit of 3-D is the improved structural image of the subsurface as a result of 3-D migration, i.e. the elimination of off-linestructures. A second benefit of 3-D is the ability to visualize the subsurface in 3 dimensions. This allows for a much greater level of certainty in most interpretations, A third benefit of 3-D takes us beyond the realm of mapping reflection times, that is locating the container, to analysis of reflection character in order to see inside the container.

Understanding and interpreting reflection character have always been parts of the explorationist 's toolkit. In the past, numerical methods designed to make such analysis moreobjective were plagued by inconsistencies related to the inaccuracies of 2-D data. Our experience is that tools such as numerical inversion (impedance estimation), analysis of amplitude variation with offset (AVO) and geostatistics can be used with some real success once a good 3-D dataset is in hand.

The tangible benefit to the exploration process of these numerical tools is the ability to quantify reserve potential and estimate risk. It is obvious that as one tries to justify drilling for smaller targets, one must be able to concurrently increasethe chance of success if reasonable economic hurdles are to be met. The following two case histories demonstrate our experiences with these tools.

Case 1: Taking Marginal Prospects To Profitability

The first case history focuses on the use of advanced seismic imaging techniques to accurately estimate reserve volumes on prospects thought to have marginal economics. With theseprospects, small reserve fluctuations can take a well from being profitable to one that you wished never had been drilled.

This example is from the offshore Gulf of Mexico and involves the analysis of a potential hydrocarbon indicator (" bright-spot") that could not be drilled from an existing platform and therefore, required the setting of a satellitestructure and a tie back to existing production facilities. The potential hydrocarbon indicator is seen in the upper right corner of the seismic line in Figure 1,
The Experimental Verification of Extreme Value Response of a Moored Tanker
Authors: Mirza Saadat , Hunstad Gry
Published: October 2008

For the design of a mooring system, extreme values of the motion response of Floating Production Storage and Offloading vessel moored in random seas must be investigated. The tank test results of a model of such a tanker anchored in 800m of water are analysed. The extreme valueestimation for the high and low frequency response was done by methods detailed in Naess I, and the API RP2P2.

The main conclusions are that the Gaussian method underestimates the prediction. The API RP2P underestimates the heave and the roll motion of the tanker, but shows good comparison for surge, sway and yaw. The SRSS (Square rootof sum of squares) gives results which are equivalent to the API estimation. Both the Least Square method and the Modified SRSS overestimate in some cases. The underestimation of the loading in the heave direction by the API code has been taken into account in the design.

The statistical parameters are compared with similar published data to show the dominance of the 2nd order effect on motion response and the tensions in the mooring lines. Further analysis was done by dividing the time history inoverlapping intervals as proposed by Kinoshita3. The influence on the estimation of the extreme values are discussed.

The significance aspect of the work is the prediction of extreme values from either the time series simulation or the experimental data of limited length to help in load estimation of mooring lines.

Introduction

In the future, the oil and gas industry is heading towards exploration and production in deeper waters, the ability to understand and predict the dynamic behaviour of moored floating structures is therefore of great importance. The significance of the low frequency response in relation to thewave induced responses and the total responses is an important matter.

In the analysis of the motion response of a floating structure moored in random seas, it is important to investigate the extreme values of the motion. This motion response has a quadratic component, which is normally called the slow-drift motion. The quadratic response is non-Gaussian in nature, although the total response is generally treated as Gaussian (Ref. 3).

It is known that the dynamic behaviour of moored floating structures to a large extent is characterised by non-linear phenomena. This makes experimental work particularlyimportant. For complete studies of the key phenomena of the motion behaviour of the system and the resulting extreme responses, the combination of experimental work with parallel theoretical/numerical work is often an optimal solution. The estimation of extreme values by mathematical techniques have been proposed by various authors in the past. Naess4 gave an explicit expression for probability distribution of 1st and 2nd order response. But the Formula was too complicated for practical use. Kato5 presented an approximate procedure for calculation of the combined response distribution which is much easier to use.
Design and Construction of the Mars TLP Deck
Authors: Edwards C.D. , Cox B.E. , Geesling J.F. , Harris C.T. , Earles G.A. , Webre D.
Published: October 2008

The Mars TLP Deck supports a payload of 15,000 tons over an area of approximately 250 feet square, weighs 7,500 tons and was designed and built over a three year period between January 1993 and November 1995.

The design of the Deck incorporated many of the learnings from the previous Auger TLP Deck. An Integrated Deck concept was chosen, but the Deck was fabricated in five liftable modules to avoid the need for offshore mating with the Hull. The interconnection between the modules was designed to ensure that Deck performed as an integrated structure inplace, and was made practical by performing the module lifts at a quayside location. Design details were developed to enhance constructability whilst ensuring long term integrity of the structure. The Fabricator played a significant part in development and review of the Design details. Large scale use of high yield (60 ksi) steel was made for the first time by Shell in a major deck structure.

The Deck modules were fabricated by McDermott Inc. at their facilities in Amelia, Louisiana. Much of the fabrication was performed in buildings, including complete assembly of four of the five modules. Major innovations in construction practice included a much more team oriented approach to the client/contractor relationships, incorporation of light weight fiberglass grating, and a cost effective approach to fire proofing the structure. A "design while build" approach enabled the cycle time for the Deck to be reduced by six months. The completed modules were transported by McDermott to Aker Gulf Marine's Ingleside, Texas facilities where module lift, setting and integration were performed.

Deck Concept

The concept for the Mars Deck was developed early in the sizing cycle for the TLP, and incorporated many of the key learnings from the construction and installation of the Auger Deck. We wished to retain the many positive features from Auger, while making some major changes aimed at cost and cycle time improvements. These major changes were:Designing a integrated deck rather than a support frame with independent modules. This made the structure lighter (by eliminating duplication of structural elements) but also made more of the structure subject to the global (and time varying) loads on the TLP. All the major modules of the deck therefore participated in resisting the global motions of the TLP.Designing the integrated deck so that most of it could be constructed inside buildings. The deck was designed to be built in five sections (which we called modules), which were then assembled and interconnected to form anintegrated deck.Assembly of the complete deck via lifting and setting rather than offshore mating. Early in the project we evaluated several combinations of inshore/offshore sites, use ofexisting or new build heavy lift equipment, and setting in final or temporary locations, to establish the safest and most cost effective means of deck assembly.
Development of a Gas Field Offshore Thailand Using an FPSO
Authors: Davison C.
Published: October 2008

FPSOs are now well established world-wide as a cost effective method for development of offshore fields where sufficient pipeline infrastructure and other suitable production facilities are not readily available. To date FPSOs have been primarily used for development of fields which are predominately oil producers, with associated gas in some cases. However, for the first time, an offshore field which is predominately gas is being developed by use of an FPSO and several minimal facility platforms in the Tantawan field offshore Thailand by Thaipo Limited.

Design export capacity of the FPSO is 150 MMSCFD of gas at 1,900 psi, together with oil processing capacity of 50,000 bbls/d. Gas compression equipment on the FPSO consists of eight gas engine driven reciprocating compressors.

It is believed that this new extension of FPSO technology will find further application in the future in regions which have commercially viable gas accumulations, particularly in the Far ast.

Field Description

First production started from the Tantawan Gas and Oil Field in February 1997, approximately 5 years after the Block B8/32 Concession was signed. The Tantawan Area Production License was awarded in July 1995 and the Gas Sales Contractsigned with PTT in November 1995. The field is approximately 265 miles south of Bangkok in the Gulf of Thailand, in a water depth of 240 feet. Block B8/32 is licensed to Pogo Producing Company and Rutherford - Moran Oil Corporation, independent US oil and gas companies, andPalang Sophon Limited, a Thai company affiliated with the Sophonpanich Group.

The initial development scheme is comprised of four offshore wellhead platforms from which production fluids, oil, gas and water, pass through one stage of separation and are then transferred, via subsea flowlines, to a Floating ProductionStorage and Offloading system (FPSO) named the "Tantawan Explorer". The "Tantawan Explorer" is a converted oil tanker, permanently moored in the field, on which hydrocarbon separation, dehydration, compression, metering and other production related equipment has been installed. Following processing on board the FPSO, natural gas produced from the field is delivered into a 24" export pipeline owned by the, Petroleum Authority of Thailand ("PTT"). The 24" pipeline tees into a previously existing main 36" trunkline transporting gas from other fields in the Gulf of Thailand to landfall near Bangkok. Oil and condensate produced from the field are stored on board the FPSO and periodically transferred to shore by tandem moored shuttle tanker.

At time of going to press, two platforms are installed and producing gas to the FPSO which is in turn processing the gas and exporting it. A third platform is to be installed during February 1997, with a fourth to be installed later in the year.

Subsequent development of the field will include provision for additional drilling/production platforms and transfer flowlines to tie into the main supply lines to the FPSO.
Multidisciplined Team Solutions Address Deepwater Challenges in the Gulf of Mexico
Authors: Stein Wayne R. , Gardiner Nicholas H.
Published: October 2008

Two major operators have joined resources to develop the largest oil and gas discovery made in the Gulf of Mexico in 25 years. The field is expected to produce 100 thousand BOPD, and I 10 mmcf/D of gas from a tension leg platform (TLP) andI subsea well located in 3000 feet of water. I The TLP has a total of 24 slots available for long term development.

This paper will discuss the multi-disciplined team approach that was used by the operators and the service/engineering company that was selected to provide services for the project to address the considerations necessary o achieve all sought-after goals. These objectives included high rate production and maximum completion efficiencies. To obtain these, emphasis in development was targeted at managing risk, lowering system costs, and reducing cycle times, all of which were deemed as critical to the success of the project.

The methods used to coordinate participation in developing the above and to align interests in this deep water project were especially significant to its success. Of particular note is the performance incentive plan that was adopted to award bonuses to either the developers or the service performers based on the resulting skin values of the completed wells.

The completion experiences realized during installation of the first two wells are detailed in this paper. To date, one subsea well and 4 wells on the TLP have been completed with frac pack-type completions. Two wells on the TLP have beencompleted with high rate water pack-type completions. The subsea well has exceeded targeted production by 75% and has a skin of 1. This resulted in a bonus to the service company. Although the first TLP completion exceeded the allocatedcycle time, the well is producing at 45% above expectation. The accomplishments to date indicate that the team approach used was able to provide a developmental concept that has more than met team expectations.

The use of a team concept to align developmental strategies was critical to the design of the completion systems. Many unique solutions were developed through this relationship, and the seven wells completed to date verify the effectiveness of using multi-disciplined team strategies when addressing specific conditional parameters in large scale undertakings.

Background of the Project

The decision to develop the field was based on results of the discovery well. four delineation wells, six side-tracks and 3D seismic data collected in 1988 and 1993. The field consists of approximately eight reservoirs in five groups at 10,000 to 20,000 ft below sea level. Geologic ages of the formations are Pliocene and Miocene in deeper intervals, Crude gravities and sulfur contents increase in the field's shallower reservoirs while gas/oil ratios decline. The initial plans were to develop several reservoirs at the same time but to complete each well in only one pay zone. Production will be from lower intervals. The oil will flow 116 miles through an 18-in. and24-in, pipeline to a salt cavern storage site.
Standardized Swivel System for Lufeng 22-1 FPSO
Authors: Ingebrigtsen Atle B.
Published: October 2008

This paper presents the swivel system to be used for the Lufeng Field Development. A general technical description and future perspectives for the swivel system is also provided.

The Lufeng 22/1 field is located in the South China Sea. The field will be developed with Statoil's Multipurpose Shuttle Tanker (MST) as an FPSO (Ref. Fig. 1). The MST will be equipped with a compact swivel arrangement, the "Rotating Connector".

The Rotating Connector for the Lufeng field is a quick disconnectable swivel system providing two off 7" (3000 psi) flow paths, transfemng electric high power to the electric driven subsea booster pumps (5 off) together with electric and hydraulic control lines for the subsea wells. The swivel arrangement is integrated on the STP buoy and located inside the STP compartment.

In general, the Rotating Connector is a standardized swivel design which allows for the inclusion of several high pressure risers and umbilicals, providing the interface between the subsea wells and the Process Plant on the Vessel. The Rotating Connector is a passive system permitting the vessel to weathemane freely around the anchored Turret Shaft.

The technology is innovative but simple, compact and flexible, and when this technology is combined with a FPSO, a wide range of applications becomes available. It may be adapted to different field requirements to generate a safe, standardized, cost-effective and flexible solution.

Introduction

Statoil Orient Inc. is presently developing the Lufeng 22/1 field in the South China Sea. The field will be developed using five subsea horizontal wells drilled and completed on a single template, which is connected to the FPSO by means of two flexible flow line risers (Ref. Fig. 2). Due to the low wellhead pressure, energy must be added to the well fluid in order to lift the fluid and maintain pressure to the inlet of the surface processing facilities.

The artificial lift will be performed by individual electric driven booster pumps, integrated on each x-mas tree. In addition to the flow line risers, a control umbilical for the x-mas trees and a booster pump electric power umbilical will terminate on the FPSO turret.

The FPSO is a multipurpose shuttle tanker (MST) owned by Statoil, fitted with a STP buoy/mooring and swivel arrangement.

Frarno Engineering AS has been awarded the contracts of supplying the complete subsea booster pump system and the swivel system (Ref. Fig. 3).

The Rotating Connector (RC) is integrated on top of the STP buoy and located inside the STP compartment. The Rotating Connector block is assembled inside the STP buoy and made up to the swivel stack. Flexible hoses connected to the swivel is directing the process fluid via isolation valves and deck bulkhead connectors to the process facilities.

Rotating Connector for Lufeng

The Rotating Connector (patented world-wide) for the Lufeng field development is a two-path fluid swivel, each with 7" diameter, and the design pressure is 200 bar at an operating temperature of 100°C (Ref. Fig. 43).
Comparison of the RamRig versus conventional drilling systems
Authors: Skjelbred Vidar
Published: October 2008

The market for mobile offshore drilling units has changed over the two last years. In general the activity level is higher, with utilisation of floating drilling units close to 100 %. The reason for this increased activity level is mainly due to the following elements :Increased number of production wells to be drilled by floating rigs, for sub-sea field developments.New deep water areas opened for exploration.

The drilling rig technology has basically been more or less identical over the last twenty or thirty years, except for the implementation of the top drive system in the early eighties. Challenging technical requirements for exploring and exploiting harsh environments areas have motivated the industry to search for new solutions. New technology and ideas are implemented both for the type of vessel and for the drilling rig. The RamRig as presented at OTC 96 (1) is one of the contributors to the new technology.

This paper outlines differences between the RamRig (RR) and the conventional drawworks based rig (DWBR). Improvements are specifically for the following topics:Hoisting and compensating systemWeight and center of gravityTubular handlingBOP handlingSafety and working environment

The coming year four units based on the RR technology will be operative, and MH have defined further development programmes that will complete the RR and further improve its performance compared to conventional rigs. Two of these products are :Power slip joint, PSJ (2), for making the conventional riser tensioning system obsolete.TOPIN coiled tubing system (3), to reduce rig-up time and Improve system performance from floating rigs.

Introduction

The DWBR was developed early this century and as technical requirements have increased, all new developments have been added to the existing concept. The basic rig was also used when the industry went offshore and initial compensation was executed by means of bumper subs. Later on in-line drill string compensator, top mounted compensator and active heave compensator have been developed and added to the DWBR. (ref. fig. 1 Draw works based rig main functions). Further requirements for top-drive and mechanized pipe handling have also been adopted without any changes to the base concept.

For control of the equipment and the entire rig, advancedcomputer control systems have been implemented. In addition, for controlling components related to each other regarding working envelope, zone management systems are required. All these systems built into the existing rig has made it more costly to maintain and less optimized for safety and working environment.

Another problem area for operations is handling and stacking of the BOP and X-mas trees. On many rigs the layout is not suitable for the size and number of modules to be handled.
Selection and Drilling of Recent Gulf of Mexico Horizontal Wells
Authors: Batchelor Barry J. , Moyer Mark  C.
Published: October 2008

Introduction

Horizontal drilling is becoming widely implemented in the Gulf of Mexico (GOM) and is providing new profit opportunities in mature fields. Horizontal re-entries which drill new horizontal wells by sidetracking from existing production casings are particularly profitable due to lower drilling costs.

Recent Industry achievements have demonstrated horizontal re-entry technologies to be viable for the GOM, including medium and short radius directional drilling, horizontal open hole completion technology, and use of workover rigs for drilling. However, design and drilling of these wells are challenging, and Industry can benefit from approaches which improve proficiency and chance for operational success. Particularly, these wells challenge present technology in several areas, including directional design, and also design and testing of down hole equipment. Understanding of such issues is important for personnel who plan and drill these wells.

This article discusses selection, planning, and drilling of Exxon Company, USA's recent GOM horizontal drilling program, which includes some re-entry wells. Also, it discusses planning approaches and techniques used for improving the chance of operational success.

Comparing Two Programs

Two candidate prospects were compared to determine which should be drilled first from a learning curve perspective. Cost, risk, and degree of difficulty for drilling up dip prospects in thin dipping beds on a salt flank structure were assessed to be appreciably greater than for prospectscontained in a low relief faulted anticline.

South Timbalier 54 G program. South Timbalier (ST) 54 G oil prospects were contained by a faulted anticline structure with 1"-3" dipping beds (see Figure 1). Bed thickness of the objective formation was approximately 15'-25'. Existing wells which had developed deeper objectives would lend themselves as re-entry candidates for exploiting the shallower horizontal drilling prospects. Most of the horizontal intervals could be designed to be colinear with the existing well directions. Also, offset penetrations provided good geologic control in the vicinity of the targets.

West Delta 30 program.

The West Delta (WD) 30 oil prospects were contained in the attics of dipping beds pierced by a salt dome (see Figure 1). Objective sand thickness was approximately twenty feet, and dipping at 20'-30°. Re-entry candidates which would lend themselves to exploiting these prospects were unavailable, so all wells here would require setting conductor, surface, and production casings. Drilling from the available platforms would require significant azimuth changes in the directional paths. Additionally, objectives were several hundred feet up structure of previous well penetrations, and so there was uncertainty regarding the depth and strike azimuth of the beds. This geological uncertainty suggested the need for costly pilot holes, or risky hunts for the objective sand top which could require drilling at high angles for extended distances.
Barracuda Field : Installation of 34 Flexible risers in FPSO System
Authors: Teixeira Marcelo J.B. , Longo Carlos E.V. , Sertil Sergio R.R.
Published: October 2008

In order to develop new deep water fields using FPSO's, Petrobras has introduced several innovations to install 34 flexible risers individually connected to the Barracuda FPSO project.

This paper provides an overview of design of the pull in and pull out operations. It also deals with I tube dimensions considering studies of interference during the risers transference from the chain table up to the risers connection deck. Additionally, new concepts have been proposed to solve the problem of Chain Table Interface to the pull in of flexible risers to floating production systems. The following advantage of this system which have been considered:Standardization of I tube inner diameters :Standardization of Bell mouth dimensions;Standardization of riser hang off systems; Standardization of flexible riser end fittings;Development of new philosophy of pull in and pull out operations;Considerable reduction in time of diver operations;Considerable reduction in time to change pull in main shaves.

lntroductlon

The BarracudaICaratinga Pilot System will comprise satellite production wells, directly connezted to the FPSO Petrobnu-34. Each well bundle will comprise three individual lines: a 4 inch production line, a 2 % inch anuulus or service line and a control umbilical. Additionally one 12 inch gas expart line will allow the gas production to be sent to a fixed platfonn called PNA-1 located in the North Area of Campos Basin, 22Km from the FPSO (Figs 1 and 2).

This FPSO system, named Petrobras 34 (P-34) will be in service for a five year period in 835 meters (2545 feet) water depth and anchored through an internal Turret device. Nevertheless, after this period, the flexible lines will be retrieved to be reinstalled in the same oil field up to 1000 meters water depth. The Barracuda production system shall remain in service fix at least an extended fifteen years, comprising of the BARRACUDAICARATINGA Development Phases I, I1 and 111 after the Pilot System demobilization.

This paper adresses various aspects related to the engineering and installation of the flexible riser bundles of each well and the gas flexile pipe elements of rigid flexible combination riser to the Barracuda FPSO pilot system.

Project start Up

The amtract for engineering and manufacturing of the Turret was awarded in February 1995 fix a installation planned in May 1997. As part of technical requirements for the design and installation of 34 risers, some premises were established by PETROBRAS as follows:

In any situation of the FPSO draft and environmental conditions the risers should not be over tensioned, compressed or extensive bend (less than their minimum bending radius).

These conditions are associated with a 50 year return period of the environmental input data.
Pipeline Reliability Across ErodibleIActive Seabeds
Authors: Bruschi R. , Drago M. , Venturi M. , Jiao G. , Sotberg T.
Published: October 2008

Severe environmental loads on exposed pipelines can lead to excessive horizontal displacements or free spanning with subsequent flow induced vibrations. The interaction between a submarine pipeline and an erodible sea bed has important implications for design choices relevant to concrete coating thickness (and consequently for the required laying equipment) and/or pipeline burial depth. For pipelines resting on or buried in erodible seabeds affected by severe environmental conditions, design should be founded on a careful analysis of the following aspects:The soil erodibility, the bedform activity and relevant time scales.The maximum curvature which the pipeline crossing active sand waves and sand dunes can achieve.The initial pipeline-sea bed configuration and that expected during the pipeline life time.The maximum length of potential exposure and/or suspension expected to develop with respect to permissible lengths from a structural integrity view point.The soil liquefaction potential and its effects on the pipeline or adjacent slopes.

The present paper summarizes the possible scenarios for pipelines laid on erodible sea beds, the techniques used to evaluate the onset and extent of erosion and other forms of pipeline-sea bed interaction and the design criteria applicable for the different configurations which can occur. A probabilistic approach to assess the structural integrity of scour induced free spans is introduced.

Introduction

In submarine pipeline design, sea bed stability, short and long term structural integrity and protection against human intervention (such as fishing, maritime traffic and marine construction) that Can damage Or be damaged by the pipeline Dresence (Camaneto and Tominez, 1991), have to be taken into account. Environmental conditions determine the mobility of the sediments and the characteristic forms of the sea bed, (Anselmi and Bruschi, 1993). On highly erodible sea beds the pipeline causes a strong perturbation of the near bottom hydrodynamics thus leading to soil erosion accumulation close to the Depending on the consequences in terms of unexpected exposure and/or suspension, these phenomena can be detrimental to the pipeline integrity, (Bruschi et al., 1994). For instance, the development of long free spans implies that the pipeline can subsequently be exposed to dynamic amplification of the vibrations induced by the hydrodynamic field (Bruschi et al., 1986). In other cases, the interaction between the pipeline and the sea bed may result in the partial burying of the pipeline in a relatively short time compared to the operating life of the pipeline. The latter case offers the possibility of considerable savings in stabilisation works such as trenching, overweighing or other types of intervention (Bruschi et al., 1993). In addition, the mobility of the characteristic morphological features of an erodible sea bed, for instance sand waves and sand banks, are relevant during the pipeline planning stage.
Inspection and Evaluation of Offshore Pipelines in the Bay of Campeche
Authors: Valdez V.M. , Bayazitoglu Y.O. , Weiss R.T. , Valle O.L. , Hernández T.
Published: October 2008

In October 1995 Hurricane Roxanne damaged offshore installations in the Bay of Campeche. To assess the condition of significant pipelines. a major inspection program involving over 450 km of pipelines was conducted to survey the location of the pipelines and to determine their relationship to the seabed. Lines not fully buried were visually inspected by multiple video cameras. The results of the inspections were presented on charts, data files and video tapes.

These results were utilized along with existing design information to assess the condition of the pipelines and to identify locations where remedial work was needed. The hydrodynamic stability of all exposed pipelines was analyzed to determine the need for pipeline burial. Damage to the pipes, weight coatings and corrosion protection systems was analyzed on a case-by-case basis.

'The paper will review the pipeline inspection objectives, procedures, and results. Evaluation procedures using this information will be described along with a summary of the conclusions of the study.

This is one of the largest and most comprehensive evaluations of existing pipelines ever conducted worldwide and provides a model for future evaluations of aging or damaged pipelines. The improved location and condition information provide a sound basis for appropriate maintenance and operational planning for these lines.

Introduction

When hurricane Roxanne passed through the Bay of Campeche in 1995, the area's petroleum production infrastructure experienced extreme environmental conditions that put the physical integrity of the pipeline systems at risk. Pipeline failures caused by this event had a considerable financial impact. These failures were identified and repaired shortly after the hurricane in most cases.@ After an event like hurricane Roxanne, an assessment of the condition of the pipeline systems that were damaged or of strategic importance was needed. In order to make an assessment, through inspections of selected submarine pipelines and risers were needed in order to obtain detailed information about the condition of the system and to identify damage caused by the hurricane not associated with obvious failures.@ In order to properly evaluate the condition of the facilities it was also necessary to determine if the existing metocean criteria used to design the facilities needed to be revised. To achieve this purpose, a hindcast was needed of the weather and sea state conditions during the passage of hurricane Roxanne. Hindcasts were also needed of other hurricanes and strong storms that have affected the Bay of Campeche. This information could then be used to develop a statistical estimate of the 100-year storm conditions which are commonly used for design and evaluation purposes.

Using data obtained from the special inspections and from the 100-year storm criteria. mathematical models of the pipelines and risers could be prepared and analyses be made to check the stress and stability on each pipeline component.