bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Harding Move: Opening Up New Horizons
Authors: Feith Jurgina , Hoekstra J.P. 
Published: October 2008

Abstract
During July-September 1995 Dockwise successfully completed the unique load-out, transport and discharge operation of the 22,870 ton BP-Harding PDQ-unit from Korea to the North Sea via the Suez Canal on board [he self-propelled heavy-lift vessel "Transsbelf'. This unique loading operation involved skidding the 22,870 [on platform via the side of the vessel over four skidbeams. Special solutions had to be found for stability, load spreading, mooring, ballasting and manoeuvring. Due to the 2.6 meter grillage height, special procedures were required for maintaining stability during discharge by float-off. The experience gained in this project may lead to a further extension of load-out and transport possibilities on a worldwide scale, utilizing the presently available fleet of heavy-lift vessels.

Introduction
For the development of the Harding Field, located in the Central North Sea, BP Exploration Ltd ordered a Technic Geoproduction designed TPG 500 from Hyundai Heavy Industries (HHI) in Ulsan, Korea. The TPG 500 is a fully integrated Production Drilling and Quarters (PDQ), three leg, jack-up platform. The legs were specifically designed for installation above a preinstalled concrete Gravity Base Tank. The design was such that the legs could not be fully retracted leaving a protrusion of 2.2 meters from the hull, which was to have a major impact on the transport concept, The platform had a transport weight of 22,870 tons and measured 88.72 meters in length, 111.75 meters in width and had a total leg length of 121.5 meters (Fig. 1).
Due to the fact that the unit was built on a normal construction quay rather than inside a dry dock, loading took place by a skid-on method via the side of the 'Transshelf'. To facilitate this the vessel was fitted with four transverse skidbeams on deck, connected to the skidbeams on the quay. The actual loading was carried out using a skid-shoe and pulling system, the resulting elevation above the vessel's deck amounted to 2.6 m.
Furthermore, in order to optimize the initial stability, sponsoons were fitted on each side. The load transfer onto the vessel was carefully monitored and compensated with the vessel's own high capacity ballasting system.
Unique events come with unique problems, which needed to be solved by a multi-discipline team, Skidding 22,870 tons via the side of a vessel would be a unique operation in vessel or barge load-outs. In April 1993 a successful cooperation started with all parties involved (BPX, TPG, HHI and Doekwise, which resulted in the 4-track skidding concept to facilitate the transverse load-out.

Skidshoe Arrangement
A hydraulic-jack-skidshoe system had to be designed to linearize the loads on the skidbeams to avoid overstressing of the vessel and the PDQ. A special low profile skidbeam was designed to stay within the limits of the grillage height which had grown to 2.6 meters.
Liuhua 11-1 Development-FPS Flexible Risers
Authors: Kirkham Benjamin F. , Hughes John D. , Bo Zhang , Hardin Donald J. 
Published: October 2008

Abstract
The FPS riser system represented a significant challenge for the team developing the Liuhua 11-1 Field. The use of downhole electric submersible pumps was instrumental to the exploitation of the hydrocarbon reserves, with an electricpower cable riser required for each well. Regardless of the assumed life expectancy of the cables in a dynamic environment, the system had to provide for their easy recent and replacement. Including the four hydraulic control bundles and a 2-in. flexible pipe service riser, a minimum of 25 risers will be suspended from the PI%. The riser array features a support buoy and clump weight for each riser. The FPS provides the means to install and recover the risers without a support vessel. The design objectives met by the riser system included survival of the 100-yr typhoon and 100-yr soliton events. Teamwork and innovative thinking from the project team contributed to successful installation of the riser may and initial deployment of the risers.

Riser System Overview
An overview of the development of the Liuhua Field by Amoco Orient Petroleum Company (AOPC), and partners, China Offshore Oil Nanhai East Corporation and Kerr- McGee China Petroleum Ltd. is presented in OTC 8172 (Ref. 1). The subsea production system overview is in OTC 8175 (Ref. 2). The FPS riser army provides at least 25 permanent, direct links between the FPS, Nanhai Tiao Zhan, whose conversion is detailed in OTC 8187 (Ref. 3), and the subsea equipment to support field production operations. None of the FPS risers carry produced fluids, which instead are routed directly to the FPSO tanker, Nanhai sheng Li, whose conversion is detailed in OTC 8188 (Ref. 4), through the two infield production and one test pipelines. The FPS riser army consists of three types of riser, as follows:Electrical in-water power cable (IWPC) risers, one for each of the 20 to 24 planned subsea wells, used to supply power to downhole electric submersible pumps (ESPS) the use of which is detailed in OTC 8176 (Ref. 5)Four hydraulic umbilical risers, one for each branch of wells, which terminate to hydraulic distribution bases (HDBs) on the subsea manifold and which control valves, deliver treating chemicals, and convey pressure signalsOne 2-in. inside diameter flexible pipe service riser used for hydrostatic testing, batch treating, and flushing the subsea manifold system
Many configurations were evaluated for suspending the riser may from the FPS. The preferred configuration uses subsea buoys arranged in a pattern offset from the subsea wells under the FPS (Fig 1). Each riser is suspended from one of two specially built porches located under the FPS main deck and is draped in a catenary from thereto the top of a subsea buoy (Fig. 2). From the subsea buoys, the IWPCS lead to, and terminate at, the subsea well tree caps. The hydraulic umbilical risers assume a similar conjuration, but terminate at the HDBs on the central manifold.
Design Considerations in the First UKCS High Pressure/ High Temperature Field
Authors: Brubaker J.P. 
Published: October 2008

Abstract
The Erskine field will be the first high pressure / high temperature (HPHT) field- developed in the North Sea. Erskine presents a number of technical challenges requiring safe, cost effective, and innovative design solutions Specifically, a safe Normally Unattended installation (NUI) is required, severe wax and corrosion problems have to be dealt with, a process module has to be installed in a minimal space, and foremost, HPHT safety concerns have to be addressed. The Erskine design achieves (1) a planned NW visit frequency of four to six weeks, (2) transportation and processing of very waxy fluids through cold (40° F) North Sea waters, (3) transportation of hot (300° F) corrosive fluids in a carbon steel pipeline, (4) over-pressure protection without the use of relief valves, and (5) a compact, minimum area processing module added 10 an existing host platform..

Introduction
The Erskine Field is a gas condensate field located in 296 feet of water within the United Kingdom Continental Shelf (UKCS) 150 miles east of Aberdeen. Recoverable resumes are estimated at 335 BCF of gas and 75 MMBBL of liquids. The field design production rates are 117 MMSCFD and 30,650 BOPD. The field was sanctioned and approved in April 1995 and plateau gas sales will commence 1 October 1997. The field development configuration is shown in Fig. 1 and consists of a NUl tied back to a Host Platform (Lomond Platform) 19 miles distant via a 16' nominal bore multiphase pipeline. A dedicated processing module will be installed on Lomond. The module will receive the multiphase fluids and separate, process, meter, and export the dried gas and condensate into the existing CATS gas system and the Forties Pipeline System respectively. The design of the Erskine facilities had to overcome a number of technical challenges.The Erskine HPHT reservoirs have initial bottom hole conditions of 14,000 psia and 350°F, wellhead shut-in pressure (WHSIP) of 10,600 psia, and flowing surface temperatures of 300° F.Production fluids contain up to 33 ppmv H2S. 5.5 mole % CO2ard 90,000 ppm Cl'.Field reserves are considered marginal for North Sea development.Condensate contains approximately 10 wt. % wax forming compounds.Host platform is located 19 miles distant.The host platform space for module footprint is limited 10 a 30 ft by 61 ft area.
Technical solutions to these field challenges have taken the following forms:

Minimum Attendance Installation.
In an effort to reduce personnel risks to as low as practical, all aspects of the Erskine platform have been designed to minimise manned intervention. Many NUI'S require one or more weekly interventions. The Erskine platform has a maximum planned visit frequency of once every four to six weeks.
Prevention of Severe Slugging in the Dunbar 16' Multiphase Pipeline
Authors: Courbot A. 
Published: October 2008

Abstract
The occurrence of the severe slugging phenomenon in multiphase pipelines can cause serious and troublesome operational problems within the receiving process facilities.
This paper describes: the pipeline operability studies on the Dunbar to Always multiphase pipeline regarding riser-induced severe slugging; the control scheme selected to prevent this phenomenon; and the subsequent operating experience. The pipeline operability studies involving dynamic simulations concluded that riser-induced severe slugging could occur over a wide range of production rates, in particular when the ElIon gas is unavailable.
The challenge for TOTAL was to develop an operating strategy and a control scheme in order to eliminate severe slugging and operate the pipeline without significant process upset.
An automatic control scheme was selected which offered a cost effective solution and ensured the safety of the existing process installations. Its originality was that it was based on a Riser Base Pressure Control.
Since the initial start-up in December 1994, this selected scheme has proven to be successful and has enabled the pipeline operations in the riser-induced severe slugging region to be carried out without any difficulty.

Introduction
The Dunbar field is situated in the UK sector of the northern North Sea, approximately 22 km to the South of Alwyn North field which has been operated since the end of 1987 (Fig. 1 and Fig. 2).
The recent development of the Dunbar field and its satellite ElIon comprises a production platform linked to the Alwyn North platform by a 16' multiphase pipeline (Fig. 3). The gas from El- Ion (Subsea wells) and the oil and gas from Dunbar are co-mingled and the overall well-fluid production is routed without separation to the Alwyn North processing and treatment facilities.
The Dunbar 16' Multiphase Pipeline has been designed to export the Dunbar and Ellen production to Alwyn North (NAB platform) at a maximum flow of 49000 BOPD and 7.9 MMSCMD. Over a wide range of production rates, in particular when the ElIon gas is unavailable, the pipeline operation is in an unstable region where riser- induced severe occurs.
The purpose of this document is :. to give a short description of the flow regimes predicted in the DUNBAR 16' Multiphase Pipeline and in particular of the severe slugging phenomenon.to present the operating strategy and the control system developed by TOTAL in order to prevent severe slugging and to operate the pipeline without occurrence of significant process upsets.and to give a feed-back of the pipeline operation at low flow rates

1. Flow regimes and severe slugging
The pipeline profile of the Dunbar 16' pipeline is represented in Fig. 4. The flow regime map for this pipeline operated at a NAB riser-base pressure of 74 is given in Fig. 5 This map was based on the results of dynamic simulations performed with the OLGA pipeline software.
In-Situ Polymerisation of an Inflatable Composite Sleeve to Reline Damaged Tubing and Shut-Off Perforation
Authors: Saltel J.L. , Leighton J. , Faure A. , Baaijens T. 
Published: October 2008

Abstract
Finding an effective solution to seal-off perforations. whether it be to reduce gas flow, reduce water cut. or to modify injection profiles. has long been a subject of concern. Several solutions for through tubing shut-off have been tried with a varying level of success
After 3 years of testing a new technology has been developed to manufacture a composite sleeve using elastomers. fibres and thermo-setting resins. The sleeve is run-in on electric wireline, inflated to push the composite against the inside of the casing, then heated to polymerise the resins. The running equipment is extracted to leave a pressure resistant inner lining in place. There is little diameter loss, leaning access to the well below, and opening up applications for tubing repair. Following successful field trials commercial operations have begun.

Introduction
Composite material are generally composed of reinforced fibres such as glass, carbon or steel bedded in a matrix. The fibres generally provide the majority of the strength and the matrix serves to maintain them in place and to transfer the stresses to them. The matrices used may be soft or rigid :flexible matrices can be used for deformable products When this is the case, the matrix is mainly an elastomer. It has almost nothing to do with the mechanical strength, but acts solely as a binder for the fibres (protection, seal), Among other applications, some examples are various types of seals, car tires, membranes, etc.Rigid matrices form products that are not deformable and provide a degree of strength to the composite material. especially in the crosswise direction of the fibres.
Fibreglass boats, fibreglass easing, are common examples. Very generally. a product is used either in a flexible and hence deformable state or else in a rigid and hence unreformable state.
Using the deformability properties of a composite material with a thermo setting matrix in its unpolymerised state, while preserving its great mechanical properties obtained after polymerisation has several advantages. The crosslinking of the resin occurs directly at the place where the end product will be used. and not dring manufacturing as it is usually the ease. This means the composite can be shaped to the desired form in the wel1.and opens up a multitude of potential applications. For example composite easing can be manufactured in lengths of up to 1,000 meters and enable mono-diameter well to be designed with considerable savings. The first available application of this technology is the Patch-Flex, designed for remedial applications. A short composite tube manufactured with thermosetting resins is run on electric wireline opposite the zone to be treated. It is inflated and polymerised to leave a self supporting cylindrical lining3 (Fig. 1).

Operating Principles
Product and Equipment. Run and set in electric wireline (Fig. 1 and 2) The Patch-Flex itself is composed of two principle parts (Fig. 3).
Coiled Tubing Drilling: Real Time MWD With Dedicated Powers to the BHA
Authors: Leismer Dwayne , Williams Brock , Pursell John 
Published: October 2008

Abstract
This paper describes and analyzes the development and ongoing field trials of a Real Time MWD Coiled Tubing Drilling System. The new system holds great promise for advancingthe state of coiled tubing drilling for certain applications. The system is designed for through-tubing, short radius re-entry and drilling highly deviated wells as horizontal laterals to a geologic target with minimum wellbore tortuosity. Currently, 4- 1/2' production tubing is the smallest re-entry candidate. Real time MWD and Bottom Hole Assembly (BHA) control is achieved by the use of a combination hydraulic and electric umbilical internal to the coiled tubing (CT), allowing continuous data collection and selective surface control of the BHA components, This communication line allows orientation in 10' increments (or less) while drilling, applies weight-on-bit and operates a reusable circulating valve. In addition, the umbilical provides real-time monitoring of weight-on-bit, circulating pressures of the drilling fluid internal and external to the BHA, dedicated hydraulic system bottom hole pressure, downhole temperature and survey data from logging equipment.

Introduction
In. June of 1992, Cameo Products & Services formed a coiled tubing drilling team that consisted of engineering representives from Reed Tool Company, Hycalog. Cameo Coiled Tubing Services and Cameo Products & Services. The team's objective was to investigate the technical and economic viability of drilling with CT. Invitations were extended to experts and consultants with experience in slim-hole and CT drilling to address the team on existing and potential problems. The major technical difficulties identified were:CT bucklingpipe fatiguelack of real-time dataweigh t-on-bitreactive torquedependable emergency release from the BHAability to drill under balanced
Key to solving these technical difficulties is the ability to provide hydraulic and electric power to the BHA via an umbilical installed in the CT, The umbilical allowed the development of hydraulically and electronically powered down hole tools and instrumentation that comprise the BHA. Purpose built surface equipment designed specifically for the BHA was developed to provide surface power and selective controls.
After conceptual drawings of the BHA were completed, Cameo and BP Exploration (Alaska) began a development project for specific application at Prudhoe Bay, where CT drillingtechnology is considered to be a very valuable tool. Many of the existing wells at Prudhoe Bay could potentially benefit if replaced with horizontal completions. CT drilling offers the potential of achieving horizontal sidetracks without pulling the existing tubing. This offers a significant cost advantage over conventional sidetracks.
Waxy Crude Oil Production in the South China Sea
Authors: Low W.R. , Gerber E.J. , Simek L.A. , Brown John 
Published: October 2008

Abstract
The Philips petroleum international Corporation Asia (PPICA) XI Jiang field Development Project Is a unique project resulting m the production of a waxy crude oil. The crude oil IS produced on two platforms feeding a final production unit located on an ITS() (floating Production, Storage and (XT-loading) vessel located between the platforms (see Figure 1)

Introduction and Background
The Xi jiang field is located approximately 80 miles southeast of I long Kong m the South China Sea It was discovered by Phillips Petroleum Co and China National Offshore Oil Company (CNO(IC) in early 1983 after initial seismic tests were pa-forward The first wells were spudded for blocks XJ24- 3 and XJ30-2 on Nov 29, 1984 and Jan. 15, 1984, respectively:.
The two platforms arc located in blocks XJ24-3 and XJ30-2 m approximately 330 feet of water These two facilities arc separated by about 45,000 feet the FIWO is located approximately midway between the two platforms.
The oil is produced and is subjected to initial water separation and de-gassing on each of the two platforms The resultant crude oil water emulsion IS pumped to the FPSO. The production module located on the vessel contains a second stage of separating, and a dual-stage dcsalting module. The resultant product crude 0il has a vapor pressure of less than 13 psia at 135, contains less than 0.5%BJS&W and less than 20 PTB (pounds per thousand barrels) of salt It is sent to storage tanks located with the vessel's hull off-loading occurs at intervals based on the production rate from the platforms
Each facility is designed to handle a peak production rate of 46 MBOPD through 16 producing well the producing wells each have an electric submersible pump (ESP) installed The maximum production rate for any one of the wells will be 10 MBPD total fluids. Along with the producing wells, there will be 5 or 6 water injection wells on each platform to provide a water flood mechanism to each reservoir. Water injection facilities will be designed at a future date.
The facilities on each platform provide for both the primary crude flashing and removal of free water. The crude and remaining emulsion is heated to 180° F and pumped to the FPSO each platform is connected to the FPSO by a sub-sea pipeline with pipeline end manifold (PI.IIM) and flexible riser.
The FPSO contain a dual-train process allowing stabilization, dehydration and desalting of the crude oil prior to storage and sale Disposal of the separated produced water overboard is in accordance with National Environmental Protection Agency (NFYA) water quality standards
The crude from these two fields contains a high concentration of wax has a relatively high pour point temperature. The crude composition and oil properties are listed in Tables 1 and 2 Special consideration was needed with respect to operating temperatures, start-up and shutdown procedures
Wide Tow Marine Seismic Surveys: Parallel or Opposite Sail Lines
Authors: Brink Mundy , Roberts Graham , Ronen Shuki 
Published: October 2008

Abstract
Wide tow seismic surveys include multiple streamers dragged behind the boat with streamers laterally offset by up to hundreds of meters from the sail line. Each sail line, or pass, thus provides a coverage of a few hundred meters wide. It allows an increase in the pass interval, a reduction in the number of passes and in the acquisition cost.
While wide tows are effective to reduce the acquisition cost, they provide data which may be problematic to image. If the acquisition and processing do not take into account the dip-dependent coverage, the output image may have severe amplitude and phase distortions.
The problem is that the sub surface coverage of a wide tow pass depends on the subsurface structure. On flat reflectors the reflection point is under the midpoint between shot andreceiver. This provides coverage which extends half way to the outer streamers on each side of the sail line. On dipping reflectors, however, the coverage is wider than half way to the outer streamer for down dip reflectors and narrower than half way for up dip reflectors. This creates problems for the imaging of up dip reflectors.
It is therefore recommended to alternate sailing direction between adjacent passes. Thus the narrowing of the coverage of one pass will be compensated by the widening coverage ofits neighbors. Because of variations in shooting directions we require an additional correction for receiver movement.
For old data collected before this phenomena had been noticed. or in cases where alternating sailing direction is notdone. advanced processing such as Inversion to Zero Offset (IZO) can produce acceptable results. However, the AVO gradient ay suffer from an acquisition footprint on dipping reflectors.

Introduction
Increased density of spatial sampling in a cost effective way was made possible for 3D marine seismic surveys by the deployment of multiple sources shooting into a distribution ofmultiple cables. A typical state of the art configuration consists of dual sources and a series of streamers covering a swath of several hundred meters with each boat traverse. In order to understand and quantify the impact of these marine acquisition geometries on final processed data quality, a study was initiatedby Saga Petroleum and Geco-Prakla. Brink and Larssen1 described results from the first phase of this study which focused on the impact of the acquisition geometry on the applicationof DMO techniques. This paper is a continuation of this work. It describes the impact of wide tow marine acquisition on DMO and suggests methods for improvement.
Wide towing becomes an issue since seismic data acquired from a single source shooting into a wide cable configuration requires careful handling with regard to the application of processing algorithms which assume 2D geometries and those which are dependent on regular dense spatial sampling. We know that poor spatial sampling adversely affects the performanceof wave equation based processes such as dip move out (DMO) and migration2.