bluuebunny/crossref_metadata_2025_split huggingface dataset:
Modeling of Pigging with Production Fluids in a Single Flowline
Authors: Dykhno L.A. , Hudson J.D. , Harris J.A. , Seay M.R. 
Published: October 2008

Abstract
Selection of a single flowline tieback subsea configuration with a reliable subsea pig launcher is often the most cost attractive option for deepwater developments. Pigging in such systems may be applied for de-watering during commissioning, for removal of untreated fluids after an unplanned shutdown, for wax removal, etc. Production fluids could be used in this case to propel the pig along the pipeline. This results in significant challenges in terms of pigging control and effectiveness. Furthermore, in many cases the pigging operation needs to aligned with other operations. For example, during start-up, fast ramp-up times are desirable in terms of hydrate management and chemical usege; however, without effective controls, the pig velocity will increase dramatically in the deepwater riser so that effectiveness may be compromised. Thus, controling the movement of the pig may prove quite challenging, but is aided by detailed transient analyses. The results of such numerical analyses (using OLGA-2000) will be presented in the paper. The simulations were performed to support system design and operations planning for a deepwater development. Optimization of process parameters are discussed along with the potential for topsides control.

Introduction
In terms of capital considerations, single flowline tiebacks are an attractive option for deepwater applications; however, a number of significant flow assurance issues remain to be addressed including:Maintaining the ability to sweep out residual water in the flowline during a cold restartThe ability to sweep low pH fluids out of the flowline after completion or stimulation activitiesThe ability to scrape deposits, such as paraffins, off the flowline wallThe ability to sweep fluids out for corrosion control (or to distribute corrosion inhibitor) during late life, should the lines begin to operate within startified flow regime.
Recently Shell has investigated technologies that could mitigate some of the above considerations. One technology is under consideration is the use of a subsea pig launching system that utilizes production fluids to propel the pig. A key added benefit of such an application is that production downtime is minimized during the operations.
There are several potential limitations of the application of these technologies to deepwater such us:Pig integrity and robustness - if application involves long term storage subsea;Design and feasibility of equipment and pigs for wax control applications, including the ability to conduct progressive pigging;Maintaining control of a pig being propelled by multiphase production fluids, particularly with respect to the risers and topsides onboarding facilities.
The latter aspect is under consideration in this paper.
Malampaya Deep Water Gas To Power Project - An Overview - Powering The Philippines Into The New Millennium
Authors: Greer David J. 
Published: October 2008

Abstract
The Malampaya Deep Water Gas to Power Project (the Malampaya project) reached a major milestone when the Declaration of Commerciality for the project was signed in May 1998. In just less than 31/2 years, Shell Philippines Exploration B.V. (SPEX), as Operator, successfully completed this remote deep water gas project, and successfully accomplished two additional major milestones by landing gas for power plant commissioning to its downstream buyers by October 1st 2001 and commencing commercial sales deliveries shortly thereafter on January 1st 2002.
This paper describes the history behind this landmark undertaking, the trade-off between alternative deep water development solutions, the contracting strategies employed as well as the many venture management, technical, HSE, commercial and sustainable development challenges that were undertaken by SPEX to successfully transform this exciting deep water project from a vision into a reality.
The Malampaya project marks the dawn of the natural gas industry in the Philippines, illustrating the crucial importance of integrating the development of gas markets with the rapid construction and successful operation of the necessary deep water and onshore infrastructure. The Malampaya development comprises five novel subsea wells in 820 metres of water, producing via a subsea manifold and two 30 km long, 16 inch flowlines to a concrete gravity platform located in 43 metres water depth. These wet gas flowlines, with their large vertical displacements and mixture of gas and liquids have pushed deep water subsea gas development technology to higher levels. The platform production facilities were installed on a concrete gravity substructure that was built in Subic Bay, Philippines and completed some 3 months ahead of schedule. The topsides facilities were fabricated in Singapore and were towed over 2200 km to the Philippines on March 1st 2001. The gas and condensate is treated on the platform to export specification. Gas is compressed and transported via 504 km long 24 inch pipeline to an onshore gas plant at the site of the Shell Refinery at Tabangao (Batangas, Luzon Island). The condensate is stored in the platform concrete substructure caisson and exported approximately every two weeks via shuttle tankers. The Malampaya pipeline is a major engineering accomplishment in its own right, traversing rugged sea floor topography through seismically active and environmentally sensitive regions. An onshore gas treatment plant, built to remove the H2S content of the gas will serve as the delivery point to the buyers.
The project schedule to meet the 1st October 2001 first gas flow commitment to the gas buyers was very tight from the outset. The project goals were achieved by continued attention to the six project tenets of cost containment: schedule attainment, use of innovative technology, high system availability, exemplary Health, Safety, Environment and Security (HSES) management, and Sustainable Development.
Malampaya Deep Water Gas-to-Power Project: Malampaya Subsea Development
Authors: Seaver J. 
Published: October 2008

Abstract
The Malampaya field development comprises subsea wells in 820 metres water-depth producing via a subsea manifold and two 16 inch diameter inconel clad flowlines to a shallow water platform 30 km distant in 43 metres water-depth. 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 for 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. 1).
The Malampaya development is unusual insofar as it is in a remote deepwater location offshore the Philippines and utilises subsea wells as the sole supply of gas to electricity power generation stations located on the mainland. Many challenges had to be overcome to realise this latest advance in the development of deep water subsea production capability:High reliability and system availability requirements;Difficult flow assurance aspects including hydrate prevention and high liquid hold-up in the flowlines;High production rate wells, high H2S and CO2 content of produced fluids requiring CRA materials;Installation and operation in a remote location devoid of the customary support infrastructure.
The Subsea System design focussed on achieving the highest levels of overall system availability. This was achieved by a combination of simplifying the design where possible and providing suitable levels of redundancy. Thisapproach was supplemented by applying the highest levels of quality assurance and control during the manufacturing phase. Finally, a full system integration test was undertaken prior to installation offshore to simulate the in-service conditions and verify the system performance.
This paper describes how these unique challenges were addressed during the realisation of the Malampaya Subsea System.

Introduction
The Malampaya Subsea System consists of a 10-slot subsea manifold with the wells positioned on both sides of the manifold (Fig. 2). The wells are tied-in to the manifold using rigid tie-in spools and separate flexible "flying leads" for providing electric and hydraulic control to each well. The two 16 inch dia flowlines are connected to the subsea manifold using rigid tie-in spools approximately 50 - 65m in length. The flowline tie-in spools are designed to accommodate the thermal expansion at the ends of the flowlines of approximately 2m. Electric and hydraulic control, methanol injection and annulus venting capability for the Subsea System is provided by two subsea umbilicals tied-in to the subsea manifold. The capability to tie-in the third 16 inch dia flowlineis provided by using a "tap it later" tee located on the subsea manifold. The capability to tie-in a third subsea umbilical to the manifold is also provided.
Spoolable Bonded Flexible Pipes for Gas Service
Authors: Antal Sándor , Nagy Tibor , Grépály István 
Published: October 2008

Abstract
The paper describes the key properties of the bonded flexible pipes, including the recent development of bonded flexible pipes; especially for choke and kill systems as well as for continuous high pressure gas service. The construction and the qualification procedures acc. to API specifications 16C [1], 17K Draft5 [2] and RP 17B [3] are discussed. An interesting application example is introduced, which is believed to be the first integrally floating high pressure line for live crude oil. The advantages and limits of the bonded flexible pipesare presented.

Introduction
The oil industry uses large quantities of flexible pipes, basically for offshore oil drilling and production, but frequently onshore as well. Their onshore application can be explained with the possibility of easier assembly and the unequal subsidence of the equipment due to the production, but for offshore production in many cases there is no other solution at all. The connection between the fixed equipment placed on the seabed and the floating drilling or production units can only be achieved by flexible pipes. There are two basic flexible pipes: "unbonded flexible pipe" described in API (American Petroleum Institute) Standard 17J [4] and "bonded flexible pipe"; at the date of submission of the manuscript the relevant API 17K Standard is in Draft5 stage [2].
The unbonded flexible pipe construction consists of separate unbonded polymeric and metallic layers, which allows relative movement between layers. In the bonded flexible pipes the steel reinforcement is integrated and bonded to a vulcanized elastomeric material. Both constructions are spoolable; the bonded construction is generally used in short lengths up to 30-40 m, but it is available upto 200 m single pieces. Longer lines can be assembled with intermediate couplings.
The bonded flexible pipe is a very special composite structure, where the reinforcing material is steel cable or wire laid in specific angles and the continuous phase is rubber. The modulus difference between the reinforcement and the continuous phase is much bigger than in any other composite, 5 orders of magnitude. This results in unique properties of bonded flexible lines.
The flexible lines are used in numerous applications e. g. as rotary drilling hoses, choke and kill lines, production flow lines, gas or water injection, pile driving etc. In the present paper we focus our attention to those applications, where the lines are exposed to high pressure gas service. This is the case with choke and kill lines intermittently, and with production, gas injection and gas export lines continuously. The experiments were carried out on particular design of cable reinforced flexible pipes. More details can be found in references [5;6;7;8;9]. Since bonded flexible pipe manufacturers use different components, coupling designs etc. special care had to be taken in generalization of the statements, especially if the reinforcing material is solid wire, not cable.
Potential Hydrocarbon Plays of the Gulf of Mexico
Authors: Lowrie Allen , Somoza Luis , Gardner Joan M. , Klekamp Thomas L. 
Published: October 2008

Abstract
Due to a complex geologic evolution, the Gulf of Cadiz hydrocarbon province contains a complex petroleum system. North Atlantic rifting caused deposition of sedimentary sequences that show a progression of facies from riverine to lacustrine to evaporites to marine sediments. Concomitant tectonically induced basin subsidence occurred as rifting progressed. The Alboran Domain, underlying the present Alboran Sea, began moving westward from western Mediterranean in the Miocene as result of the northwesterly compression between the Iberian and African plates forming the Gibraltar Arc.
Westward crustal motions caused serial events: upper slopeover steepening triggered major mass-wastings to descent some 500-600 km downslope forming the accretionary wedge of the Gibraltar Arc. Simultaneously, subshelf basins developed and were infilled with material from the nearby shelf and Guadalquivir Basin-river system. Across the continental margin, extension occurred over the upper slope and compression along the lower slope.

1.0 Introduction
The Gulf of Cadiz continental margin has been proposed as a potential world-class petroleum province1, 2. The margin is a known hydrocarbon producer with largely biogenic natural gas extracted under the continental shelf1 Abundant evidence exists for pockmarks, i.e., mud volcanoes with natural gases sampled from them (research conducted by Joan M. Gardner and Luis Somoza, 2000 and 2001), along the upper and middle continental margins off the Gulf of Cadiz and Morocco). Thus, these margins are undeniably petroliferous.
A complex tectonic history beginning with the Triassic-Jurassic North Atlantic rifting to the present3 has resulted in a complex petroleum system,1 based on sizable seismic data sets, including high and low frequency lines. Figure 1 is the location of industry-quality data. These lines were collected in he 1970s and 1980s by industry for hydrocarbon exploration. The data set spans the continental shelf, the upper slope, and the down-to-middle slope in water depths up to 1000 m.
The overriding geologic problem is that the measured geothermal gradient along the shelf (2.4°/100 m) is too low to cause a hydrocarbon column that has been reported to be some 2.0 to 2.5 s two-way travel time (t-wtt) thick1 (also see Figs. 2, 3, and 4), with sediments extending to depths of 3-3.5 s, apparently interspaced between rising (from east to west) thrusts of continental rocks. The actual sediment thickness may reach 4 to 6 km, possibly even 7 km at maximum depths beneath the thrusts1,2(Fig. 2).
Figure 3 shows that with basement thrusting from east to west, the thrusts may override thin (&lt; 100-200 m thick) sediment wedges (Fig. 3a) and that advancing thrusts impact the sediments, initiating fracturing deformation of the thrusts (Fig. 3b). Continued thrusting heavily fractures the sediments, shattering them; fractures possibly radiate from the advancing thrusts for a distance equal to the thrust diameter (Fig. 3c).
Ceiba Field Development Project Execution
Authors: Brashier Robert S. , Pavia Anthony P. 
Published: October 2008

Abstract
This paper will describe the project organization, methods, philosophy and execution used to develop the Ceiba Field; a fast track, two phased, subsea tieback to an FPSO, offshore Equatorial Guinea. It will detail the advance planning that was done by Triton Equatorial Guinea, Inc. (acquired by Amerada Hess in August 2000), the engineering study performed for Ceiba, the process by which primary contractors were selected and how the coordination of various aspects were handled. The paper will discuss the installation of the early production system and startup of the field in less than 14 months from discovery and subsequent expansion of the system in the following 14 months.

Introduction
Triton discovered the Ceiba Field in October 1999 in the previously under-explored Rio Muni Basin in the Gulf of Guinea, offshore Equatorial Guinea. Following the discovery well, Ceiba-1, and drilling of the confirmation well, Ceiba-2, Triton embarked on an aggressive development with prudent risk management to achieve first oil production in a record setting 14 months from discovery. (Figure 1)
The Ceiba Field development was implemented in two phases. Phase 1 is an early production system whereby four subsea trees and manifolds are tied back to a spread moored FPSO in shallow water. Water depth at the FPSO location is 90 meters and approximately 700 meters at the subsea wells. Each Phase 1 well is tied back to the FPSO via dual 8" insulated steel flowlines with flexible jumper connections to the manifolds. Flexible risers from each flowline are supported by a riser support structure (RSS) set on the seabed adjacent to the FPSO. Separate multifunction control umbilicals are routed along the flowline routes to the individual manifolds withintegral subsea distribution units (SDU).
Phase 1A was implemented in parallel with Phase 1. While Phase 1 equipment was being fabricated and installed, Phase 1A engineering, design and start of manufacture was in process. Phase 1A added two, four well production manifold systems; three, four well water injection manifold systems; and one satellite water injection well. Production manifolds are tied back to the FPSO with dual 10" flowlines. Water injection manifolds are tied back with single 10" flowlines. Additional processing capacity on the FPSO for production and water injection was accomplished by changing out the FPSO rather than adding process modules in the field. Phase 1A start up occurred 14 months after the Phase 1 first oil milestone.

Ceiba Development

Early Planning and Conceptual Engineering
By the end of the first quarter of 1999, Triton had assembled a multi-disciplinary team of exploration and operations personnel to develop a plan for drilling and appraisal of Triton's license acreage in Blocks F and G. Concurrent with the exploration team work, early in-house conceptual engineering work was done with cost estimating software and information in the public domain. This work helped to evaluate possible development concepts and was incorporated into project economics.
Ceiba Field Operational History
Authors: Hopkinson J. Michael 
Published: October 2008

Abstract
This paper describes the operational history for the Ceiba Field. The FPSO vessel and process equipment is detailed together with external support required for servicing the facility and exporting crude oil. Areas of particular interest including operational problems and the related solutions are also detailed.

Introduction
The Ceiba field, offshore Equatorial Guinea, West Africa was discovered in October 1999. The water depth at the field is approximately 700m. Development of the prospect started immediately leading ultimately to fist oil being produced from four subsea wells tied back to an FPSO approximately 5 miles distant. Hydrocarbons were first received on the FPSO Sendje Berge on November 22nd, 2000, fourteen months after discovery. To achieve this difficult task many engineering judgements were made with a view to maintaining flexibility of the surface and subsea systems in the future. The following paper describes the operational history together with the steps that were taken prior to production to maximize production uptime.
The field to this point has been developed in two phases. The first phase is namely "Phase 1" which includes wells Ceiba 1, Ceiba 2, Ceiba 3, Ceiba 4 and Ceiba 7. The second phase "Phase 1A" includes additional production and water injection wells. Part of the Phase 1A development inclided changing out the existing FPSO for an upgraded FPSO.

Facility Description
The FPSO Sendje Berge is a VLCC (Very Large Crude Carrier) taken from the Bergesen shipping fleet and converted to an FPSO by adding process facilities and modifying the ships systems. The FPSO was moored in position using twelve pre-installed anchors. Production from subsea wells was routed to the FPSO from the wells via 8" flowlines and flexible risers to compensate for vessel motion.
Production history from the field aided in the specification and construction of a modified vessel (FPSO Sendje Ceiba) and ultimately the replacement of the Sendje Berge with the Sendje Ceiba.

Production Statistics
Ceiba first oil was on November 22, 2000. Since first oil, up until January 12, 2002 when the Sendje Berge was changed out for the Sendje Ceiba, 13,014,182 barrels of oil have been produced and exported. Nineteen export operations were conducted using a bow to bow transfer method. All produced gas that is not used as fuel gas is flared. Produced water is treated on board to reduce hydrocarbon content and insure that environmental criteria are met before being discharged overboard.
The average facilities uptime for the 14 months that the Sendje Berge was producing was 98.73%.
Bergesen Offshore provided the marine crew on board the Sendje Berge. The crew is responsible for maintaining the ship's facilities including steam used for crude heating, generation of electrical power and exporting operations. Approximately sixty people are regularly stationed on the Sendje Berge to provide this support. ABB Offshore provided the personnel to support the process facilities, a total of 10 make up the compliment of production crew.