bluuebunny/crossref_metadata_2025_split huggingface dataset:
Development of a Gas Field Offshore Thailand Using an FPSO
Authors: Davison C. 
Published: October 2008

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.