bluuebunny/crossref_metadata_2025_split huggingface dataset:
Hybrid Tubes for Choke and Kill Lines
Authors: Guesnon J. , Schaeffner P. 
Published: October 2008

Abstract
The main purpose of this paper is to present the technology of hybrid tubes developed to reduce the mass of auxiliary lines of drilling risers used in ultra deep water, by replacing conventional choke and kill lines with lighter tubes. They are composed of a steel core hoop wound with a strip made of carbon fibers impregnated with a polyamide thermoplastic resin.
The paper describes the structure of hybrid tubes, the design methodology and the manufacturing process. It presents all the tests carried out to qualify the technology and the conditions of the field test in preparation aboard a drillship offshore Angola. The principle of their integration in riser joints is described. Finally, the architecture of drilling risers including hybrid tubes is commented and their technical benefits are discussed.
In conclusion, studies performed at IFP prove that hybrid tubes reduce the weight of auxiliary lines by 50% and that this technology is well suited for ultra deep drilling risers.

Introduction
In recent years there has been a great increase in the number of wells drilled in the very deep offshore, in water depths initially slightly greater than 2000 m and now in depths approaching 3000 m. Several drilling rigs of a new generation were recently put in service to allow such operations [ref. 1]. Their huge dimensions facilitate the production and the maintenance of the necessary drilling fluids, as well as the storage and the use of a large number of tubulars. Among these, the drilling riser is definitely one of the key components for these complex operations; therefore its design and make up procedures must be studied with a great attention [ref. 2].

Drilling riser problematics
The main function of the drilling riser is to extend the borehole throughout the water column in order to guide the drillstring and to return drilling mud and cuttings to the surface. It is composed of tubular elements of 21" outside diameter, joined together by mechanical connectors. It links the drill floor of the floating vessel to the subsea wellhead where the BOP allows the well to be closed in the case of blow out. To ensure the control of the well in such a situation, the riser is equipped with two high pressure auxiliary safety tubes, called kill & choke lines. A third auxiliary tube, called booster line, is used for injecting an additional flow of mud at the bottom of the riser to facilitate the return of the cuttings. Finally, one or several hydraulic lines complete the architecture of the riser. All these tubes are integrated into the 75 ft long riser "joints". Each joint of riser is also equipped with buoyancy modules made of syntactic foam to reduce the wet weight of the system.
When studying a drilling riser, the designer has to size the tubes, connectors and buoyancy modules so that the stress levels in the system remain acceptable in all operational conditions [ref. 3]. One of the most important parameters to control is the tension in the riser, particularly at the top end.
Malampaya Deep Water Gas To Power Project-Drilling and Completing the Limit
Authors: Steiginga A. , Holmes C. , Hudson A. , Morris T. , Tosun O. 
Published: October 2008

ABSTRACT
The Malampaya field development comprises subsea wells in 820 meters water-depth producing via a subsea manifold and two 16 inch diameter inconel clad flowlines to a shallow water platform 30 km distant. Condensate is removed on the platform and the dry gas is then transported via a 504 km long 24 inch export pipeline to an onshore gas plant at Tabangao (Batangas, Luzon Island) for extraction of H2S. The condensate is stored in the platform CGS Caisson prior to export via a short 3 km long 24 inch diameter pipeline and CALM buoy (Fig 11).
The Malampaya Deep Water Gas to Power Project in the Philippines has delivered first gas as advertised on October 1st 2001. The gas production is from five high rate deep water subsea gas wells. This paper summarises the delivery of the wells, in particular, the specific challenges that had to be surmounted to deliver high quality wells whilst remaining within the tight Malampaya project schedule.
These challenges related to the deployment of leading edge well technology systems in an environmentally pristine and remote area. This within a country with extremely limited petroleum infrastructure and very long supply lines. The definition and management of good performance within this context and the management of the many interfaces with other disciplines working concurrently required unique ways of working to be established.
Within the technical arena, many novel solutions were adopted with respect to rig modifications, drilling with losses, management of hydrates, horizontal Xmas trees, monobore well completions, coiled tubing perforating from a semi-sub well test clean-up and extensive/detailed planning. Organisationally, a working atmosphere was developed based on open, detailed and relentless inter-team challenge. This led to drilling and completing, genuinely to the "limit" of what was achievable for Malampaya.

INTRODUCTION
Malampaya, developed and operated by Shell Philippines Exploration BV (SPEX), is the first and only gas development in the Philippines. The five subsea wells are the first link in a production chain that supplies 30% of the mainland power requirements. In each well, high deliverability and high availability are critical from day one and throughout the full 25 year field life. There are no other fields that can supplement any shortfall in well performance.
Planning was initiated in Houston in late 1998 and moved to Singapore and Manila in mid-1999. Offshore execution started in early-2000 and was completed by September 2001. Innovative business processes and technical solutions were employed in "striving for excellence" in an environment characterised by a very short planning time and a multitude of project interfaces.
The Malampaya gas wells were handed over to the production team, on time and within budget. They have been proven capable of production rates exceeding 120MMscf/day. Included in this paper are the key highlights from planning, drilling, completing and commissioning the Malampaya gas wells.
Comparison of Models to Predict the Annulus Conditions of Flexible Pipe
Authors: Last Sijm , Groves Steve , Rigaud Jean , Taravel- Condat Carol , Wedel-Heinen Jakob , Clements Richard , Buchner Stefan 
Published: October 2008

Abstract
Corrosion and corrosion fatigue of the steel reinforcement wires will take place if the annulus of a flexible pipe is flooded with seawater. It will also occur under non-flooded conditions if water permeates from the bore and condenses in the annulus. The combination of water or seawater with permeated CO2 and H2S gases results in a corrosive environment that may cause stress corrosion cracking, hydrogen induced cracking, pitting, general corrosion or, in dynamic risers, corrosion fatigue. The type of corrosion, its severity, and the reduction in fatigue life will depend on the actual composition of the annulus environment. Until now, uncertainties about the annulus conditions have caused difficulties in assessing the remaining service life of flexible pipes with flooded annuli or even the service life under normal operating conditions. In this context, a review has been carried out on permeation, corrosion and corrosion fatigue in flexible pipe. This paper will focus on the first step of a service lifeassessment procedure: the modelling of the annulus condition.

Introduction
The flexible pipes in the offshore industry transport water and/or oil and/or gas. Due to permeation, some of the components in the bore fluid will permeate through the pressure sheath of the flexible pipe and into the annular space between the pressure sheath and the outer sheath. Vent ports in the end fitting of each pipe will vent the permeated gas if the gauge pressure on the vent valves is reached. After some time the conditions in the annulus will reach equilibrium. The time until equilibrium conditions depends amongst others on the temperature profile across the pipe, the pressure differential across the pressure sheath and the gauge pressure on the vent valves.
In operation, water from the bore will permeate through the polymer pressure sheath. Depending on the conditions in the annulus, it may be present as condensed water or as water vapour. After dissolution of permeated CO2 and H2S, the condensed water will form a corrosive solution for the steel wires in the annulus. Sometimes the annulus is flooded with seawater, for example if the outer sheath is damaged or if an end-fitting plug is missing or badly installed. It is obvious, thatseawater in combination with the permeating gases will also cause corrosion of steel armour wires. The severity of corrosion depends amongst others on the composition of the aqueous solution and hence on the composition of the annular gas mixture. Predicting the annulus conditions in the design phase of a project is therefore important.
A Round Robin annulus prediction exercise has been performed as part of a joint industry project with the three manufacturers of unbonded flexible pipe and a number of users. This paper describes some results of the case studies. It should be emphasized that the results are equally applicable to static and dynamic flexible pipes.
The Ceiba Field FPSOs for phase 1 & 1A
Authors: Daviknes Morten A. , Hannisdal Nils-Erik 
Published: October 2008

Abstract
Bergesen dy Offshore have provided the FPSOs for both phase 1 and 1A developments of the Ceiba Field, with ABB as their process subcontractor designing, fabricating, and operating the required process facilities.
The phase 1 FPSO Sendje Berge was in operation 14 months after Triton's first oil discovery at the Ceiba Field. The upgraded (phase 1A) FPSO, the Sendje Ceiba, produced First Oil 14 months after Triton ordered the additional process modules.
This paper describes how the Bergesen generic FPSOs were modified to meet Triton's requirements for phase 1 and 1A developments, installed in field and started up, all within the ambitious schedules required by Triton.

Introduction
In October 1999 Bergesen presented the concept of a Generic FPSO to Triton Energy (TE). This coincided with Triton having issued their tender for Early Production System on the Ceiba field. The specifications and the schedule for Bergesen's first Generic FPSO were a close match to the requirements set by Triton for their EPS. In addition, the FPSO provided a very good platform for a phased development of the Ceiba field.
Moreover, the business cultures of Triton and Bergesen Offshore matched. Being part of a major shipping company, Bergesen Offshore is focused on the services to be provided, i.e. to produce oil, rather than the engineering focus often found in big offshore projects.

Generic FPSO - "The Basis"
Bergesen Offshore was founded 1999 with the objective to develop Low cost, Tanker based Floating Production Systems for use in benign areas, such as offshore West Africa.
Oil-field characteristics were gathered from oil companies with current and future activities offshore West Africa. This provided the basis for developing a Generic FPSO, which was to have process and utility systems suitable for a large variety of fields. The design should also allow for simple modifications and upgrades where this is required from operators.
In short, the FPSO should be characterised by:Designed for a wide range of fieldsLow cost to be attractive even for EPS and small fieldsFlexible design to allow for easy field specific upgradesWell suited for phased development
The two main factors that support these goals are:Tankers with ample deck spaceModularized and fit for purpose process design
Bergesen did a bid-round with several process suppliers in order to find the one that would support our objective. The selection of ABB was based on:Lean and Mean attitudeHardware-as opposed to engineering orientedFocus on delivery time.
Key factors in the design of the process are:Flexible separation design (high capacity and prepared for variety of configurations of internals.Large heat exchanger capacities.Prepared to interface various additional equipment and injection points if reservoir characteristics change.
Safety Restraint System for High-Pressure Oilfield Piping
Authors: Matzner Mark , Hayes Glenn 
Published: October 2008

Abstract
Conveying energized fluid through piping presents a significant hazard with the potential for explosion in the event of a component failure. A method is presented for a simple restraint system that limits the movement of piping to a contained area. Basic practical design equations and considerations useful for piping constraints are presented.

Introduction:
The safe constraint of piping used to convey highly energized fluid is essential for safety, but has proved to be a difficult task to accomplish. This has been especially true for temporary well service applications where piping must be light enough to assemble and remove quickly, and does not usually have the benefit of permanent anchors at the worksite.
Energized fluids, such as pressurized nitrogen or C02, have high explosive potential due to their stored energy. While pressurized liquids present their own kind of danger, a compressed gas has enormous potential for damage if freed rapidly. If a piping assembly fails, the initial forces released are those of the static pressure. Compounding the problem are the acceleration forces created as the stored medium continues to evacuate the piping. Both forces continue as long as any pressurized fluid remains in the system. The acceleration forces are responsible for most of the danger by causing the piping to move violently, placing personnel and equipment at risk.
Testing has shown that constraints with limited elasticity, such as wire rope, perform poorly in high pressure situations. The lack of a constraint's ability to dissipate the discharge energy is a reflection of not only its strength, but also its toughness. The solution to this problem is a flowline restraint system (FSR), developed by us, that manages to contain the damaged piping within a limited zone of danger.
The FSR system consists of members of tough synthetic loops that are strung the length of the piping and held in place by smaller loops attached at key points along the piping. This assembly is terminated at each end by anchoring to a substantial member such as the wellhead or a pumping truck for land based operations. Suitable structural tie-downs can be substituted for the truck and wellhead in offshore operations. Supplementary restraining loops are normally provided to further minimize flowline movement.

Theory and definitions:
The rapid discharge of energized fluid, such as pressurized nitrogen, will occur if a portion of the conduit piping fails. J.L. Stromberg and J.B. Surjaatmadja1 found that the forces applied to damaging the piping are proportional to the energy of the discharging fluid. They deduced that the steady state force of ejecting gas supplied by an infinite reservoir can be described by the following equation. (Mathematical equation available in full paper) The first set of terms on the right of the above equation represents the forces generated by the fluid acceleration out of the pipe. The second represents the static pressure force generated over the cross sectional area of the pipe at the exit.
Single Trip Pigging of Gas Lines during Late Field Life
Authors: Mandke J.S. , Shen Harry , Roscoe John 
Published: October 2008

Abstract
For flowlines used to tieback marginal fields, pigging is an essential component of the associated flow assurance solution. Single trip pigging using a single line is being pursued by the offshore industry as an economical alternative to round trip pigging using dual flowlines because of the potential savings in CAPEX and OPEX. Recently, the industry has developed subsea pig launchers which are specifically designed for deepwater and ultra-deepwater applications. However, there are significant operational challenges associated with single trip pigging that need to be resolved.
This paper draws attention to potential difficulties in the pigging of multiphase gas lines during late life field condition when the line is likely to hold a large amount of liquid. A pig travelling through such a flowline is likely to stall at the base of a deepwater riser due to the buildup of high static head of liquid column in front of it and insufficient drive energy provided by the reservoir fluid. There are some options such as using gas lift at riser base, which are available to deal with this problem. Pigging with bypass is another cost effective method to mitigate this problem. Using a hypothetical field, pigging simulation results from OLGA 2000 are presented to demonstrate how inclusion of 10 to 15% bypass in the pig benefits the pigging operation. Typical pipe cleaning pigs are limited to 3 to 5% bypass.
Another associated issue is the challenge of handling large quantities of liquid arriving rapidly on the platform topside during the pigging operation. The platform topside process train is generally not designed to handle liquid inflow at such high rates. Some potential solutions to this problem have been discussed. The optimum solution for liquid handling will have to be developed using the field specific data.

Introduction
Marginal fields in deepwater and ultra-deepwater are being developed by using tiebacks to existing nearby host platforms. Such tieback systems invariably require periodic pigging of flowlines as a part of the flow assurance solution. The traditional method of pigging deepwater flowlines has been to use two lines that connect the host platform with the subsea manifold or tree so as to provide a round trip pigging loop. In this case, the pigs are launched from the platform and received on the platform. Usually, the CAPEX for round-trip pigging systems is high. In addition, the requirement to shut-in wells, i.e. deferment of production and to buy back pig driving fluids from export lines during pigging operations could result in high OPEX. An economic alternative to round trip pigging is to use a single trip pigging system which includes a single flowline and a subsea pig launcher. Such systems utilize the production fluids to drive the pigs and there is a minimal interruption in the subsea well production. A subsea pig launcher has been successfully operated in ETAP field in the North Sea [1] since fall of 1998.
Girassol: The Biggest FPSO in the World: As Seen by Its Contractor
Authors: Loez Bernard 
Published: October 2008

Abstract
This paper describes the engineering, procurement, construction and installation (EPCI) issues encountered during the construction and assembly of the floating production, storage and offloading (FPSO) system chosen for the Girassol development, offshore Angola. This presentation is from the contractor's point of view and includes general remarks on the management of big projects.
Finally the paper adresses contractual aspects of the clientcontractor relationship, which have been carried out in a unique manner at Girassol.

Introduction
The Girassol project has been quite exceptional and it is true to say that it is greater than the sum of its parts. No matter how difficult the construction program was, however, the tale would seem banal if all of the details were recounted.
In order to avoid a tedious cascade of figures designed to demonstrate the merits of Mar Profundo Girassol, the Bouygues Offshore/Stolt Offshore joint venture, in their management of this complex project affair, it has been decided to provide the "inside story", presenting the major problems encountered and the way in which they were resolved.
Many of these problems are of a general, rather than a technical, nature and are common to the management of all major projects. In order to make this presentation more interesting, a number of famous authors have been quoted - entirely out of context, of course - in order to throw a humorous light on the matter.

In the beginning
The problems with the Girassol project began with the preparation of the tender at the end of 1997. Those in the industry are familiar with the haste with which TotalFinaElf E&P Angola decided to proceed with this development. The questions at that moment were: which type of contract for which scope of work and what type of facility was to be built and on what basis?
It was to be an FPSO, a floating unit for the production, storage and offloading of oil. It is best described as a hull with a vast production complex on its deck for the processing of oil, water and gas; storage of crude oil; re-injection of water and gas and export and metering of the crude oil.

Slide 1: Slide BFD3
The simplest and most striking way to define an FPSO is as a refinery on a super-tanker. This over-simplification masks the major difficulties on the project. It is a combination of an oil processing platform and a ship - two different cultures, different objectives, specifications, safety regulations, functions, methodologies, different contractors and construction sites. What brings them together is a bundle of interfaces and the absolute necessity for strict planning and coordination.
The objectives on such a project are so divergent that certain oil companies separate them at the contract stage. TotalFinaElf E&P Angola decided against this and one hopes that at the end of the day they are satisfied with this choice. If the economics of this decision are not apparent at first sight, the long term benefits are considerable.