bluuebunny/crossref_metadata_2025_split huggingface dataset:
Captain Field Development Project Overview
Authors: Etebar S. 
Published: October 2008

Abstract
The Captain Field is approximately 90 miles north-east of Aberdeen, Scotland in the UK Continental Shelf Block 13122a (Fig. 1). The field was discovered in 1977 and it was clear then that economic extraction of the viscous, low GOR and low API crude from a shallow, unconsolidated sandstone reservoir at a depth of 3000 ft and with a large a real extent (7 mile by 3.3 mile) would not be easy.
The Captain Field overview presentation will focus on how the dedicated, multidiscipline team brought the asset to commercial reality as quickly as possible through a parallel appraisal and engineering programme. Also, the appraisal programme was tasked with proving the horizontal drilling, completion, artificial lift and reservoir performance technology through the use of extended well tests (EWT). Contractor qualification and concept selection began while appraisal drilling and testing were being carried out. Information gained from the appraisal programme was fed directly into the Front end Engineering Design (FEED) which was carried forward with three development concepts. Detailed bids from the three FEED contractors were used to select the optimum economic development concept and plan.
From inception, the team was empowered to drive the project forward and quickly developed a set of principles that has driven its success. These principles include a shared vision, innovation, dedication, open communication, quality, standardisation, teamwork and trust.

Introduction
The Captain Field was discovered in 1977 and it was clear then that economical extraction of the low mobility viscous, low GOR crude oil, from a shallow field (3000 feet) with a large a real extent and unconsolidated sand would not be easy (Fig. 2).
The discovery well (13122a-1) drilled in 1977, contained viscous oil with little gas and did not have sufficient reservoir pressure to allow production without artificial lift. The appraisal well 13122a-2 was drilled in 1989 and tested 740 BOPD with an electric submersible pump(ESP). In 1990, a well (13122a-8) was drilled with 1000 ft Presented. horizontal section and produced 6500 BOPD, again using an ESP. The gap between the 1977 discovery well and follow-up drilling was extensive because the technical challenges were immense.

Operating Under A Business Umbrella
To meet these challenges and to bring Captain to commercial reality, a multi-discipline team was formed in January 1992 (Fig 3) as part of Texaco's U.K. Upstream reorganisation which implemented sweeping changes in the way projects were to be developed. Multidiscipline and cross-functional teams were formed in a new "Asset Development" department to address problems, such as Captain. Their charter was to map issues accurately and to develop solutions that could be implemented in a variety of settings, and then advocate the adoption of these solutions as quickly as possible, with the goal to add significant value to the Company
Captain Field Reservoir Development Planning and Horizontal Well Performance
Authors: Lach J.R. 
Published: October 2008

Abstract
The Captain Field, in UK North Sea Block 13/22a, is an accumulation of viscous, high density oil which required a development plan utilizing only extended reach horizontal wells. Parallel field appraisal and facilities engineering required a close working team since during the period of 1992 to 1994 major changes occurred in the description of reservoir fluids. Oil viscosity decreased due to improvements in sampling methods which had significant impact on recommended design parameters. Other key data acquisition and field testing provided confidence in and a linking of relative permeability data and KvKh
Fluid movement in the interwell region is dominated by gravity forces where up dip injected water slumps to bottom and water coning is a dominant feature. Well spacing of around 700-800 feet are planned. Significant water will be produced, and the cost of water handling is a primary consideration when designing well liquid flow rate. In Captain Field, the optimum well off take rate is found to be between 15,000 to 20,000 bpd.
Development plans include a large waterflood to maintain reservoir pressure at high off take rates. The waterflood will utilize only horizontal water injectors wit11 'tuned' completions. Also, careful consideration of injector placement has taken into account potential future use for polymer flooding.

Introduction
The Captain Field is approximately 90 miles north-east of Aberdeen, Scotland in the UK Continental Shelf Block 13122a in 350 feet of water. The field was discovered in 1977 and it was clear that, although large with nearly 1,500 mmbbl oil in-place, economical extraction of the high density (19° API), viscous (88 cP) and low gas-oil ratio crude (Table 1) would not be easy. Also, the two primary reservoirs, the Upper andLower Captain Sands, are permeable but unconsolidated and of greatly varying thickness (0 - 275 ft). To this end no fewer than 20 appraisal wells (Fig. 1) were required to determine reservoir extent. Also, an extensive aquifer is present and underlies approximately 65% of the hydrocarbons.
Not until performing a ten well appraisal program during 1993, which included a 90-day test of a field development prototype horizontal well, a vertical well water coning test, and further delineation drilling, was it clear that these technical challenges could be overcome. Conclusions from the 1993 appraisal program and subsequent reservoir simulation indicated that successful field development would require nearly 40 horizontal wells up to 6,000 ft long, artificial lift systems to deliver 15,000 bpd from each oil well producer, sand control completions, high temperature and high retention time fluid separation equipment to treat 60,000 bopd and 200,000 bwpd, and a single aquifer lift well to deliver 60,000 bwpd make up water for water flooding at full voidage replacement.
The Concept of Multitube Moment Factors in a Riser System and Its Applications
Authors: Li Yousun 
Published: October 2008

Abstract
In a concentric multitube riser system, individual tube motion response transfers through local contacts. The conventional riser composite model treats all the tubes as an equivalent tube and allocates the bending moments to tubes according to their stiffness ratios. Without consideration of contact mechanisms, this approach may induce large errors. Direct time domain simulation of a long duration of multitube response model including intermittent contacts may require excessive computational efforts. In the present study, the concept of Multitube Moment Factors is introduced, which accounts for the statistical correlations between the moment h mth e multitube model and those from the composite model. Multiplying by a multitube moment factor, the dynamic bending moment response from the composite model becomes equivalent to the tube moment based on the multitube model.

Introduction
A concentric multitube riser is a riser system consisting of a number of concentric tubes, such as casings and tubings. In the dynamic analyses of the riser response under stochastic wave and wind conditions, the riser system is normally modeled as an equivalent tube comprising all the individual tubes (riser composite model). The bending stiffness of the riser composite model is the summation of all the bending stiffness of individual tubes. The resulting bending moment from the composite model is allocated to the individual tubes according to their bending stiffness ratios. This approach implies that at any location along the riser all the tubes share the same bending curvature across their cross sections. In reality, all the tubes are intermittently contacting each other. The number of contacts is limited. Using the pair of an outer-casing and an inner-casing as an example, the inside diameter of the outer casing is normally uniform along its length, while the inner-casing has larger outside diameters at the connectors and centralizers than those along the tubular parts. The contacts tend to occur at the connectors and centralizers. The bending transfers from the outer casing to the inner-casing through these contacts. The bending moment is not distributed along the inner-casing smoothly. Since the contacts have clearances, the structural response of an individual tube is strongly nonlinear to the wave loads.
Direct time domain simulation of a riser model consisting individual tubes with intermittent contacts may produce more reliable results. The descriptions of the contact forces by Lagrangian Inequalities (Ref.2) can handle hundreds of intermittent contacts along the entire riser system. However, the time duration must be sufficiently long for statistics of the bending moment that may be deviated from Gaussianity. For example, the fatigue damage rate estimation by a rainflow-counting algorithm requires at least a three-hour duration of the response.
Hydrate Plug Dissociation Field Test
Authors: Hatton Gregory J. , Kruka Veet R. , Guinn James  A. , Greig Gary N. 
Published: October 2008

Abstract
Deep Star funded a unique hydrate plug dissociation field test in a 900-psi 4-inch flowline gathering system operated by Kerr-McGee Corporation/Devon Energy in the Powder River Basin in Wyoming. In addition to DeepStar, the field test was supported by seven DeepStar member f m s (Amoco, ARCO, BP, Chevron, Kerr-McGee, Shell, and Texaco) by loan of equipment and analytical and computer services. During the field test, the formation of naturally occurring hydrate plugs was allowed in an existing flowline by stopping methanol injection. After formation, plugs were remediated by a unique one-sided depressurization. This reduction of the pressure on one side of the plug to below the hydrate decomposition curve results in a substantial pressure drop across the plug, as well as partial dissociation of the low pressure end of the plug that is outside the hydrate region. Plug formation and remediation were monitored by five data stations along the line. The pressure drop across a plug was monitored as a function of time to determine plug permeability while the plug was stationary. The pressure drop across a plug and the plug length were used to determine plug yield strength at breakaway. A dual-station gamma-ray system was used to measure slug and plug lengths and velocities at one data station.

Introduction
Hydrates are ice-like solids that form in hydrocarbon flowlines. Hydrates can deposit on the flowline inner wall and agglomerate in the flow stream, and with time, hydrates can block the flowline. Hydrate operational problems are most severe in high pressure flowlines in cold environments, such as in deep waters around the world where the seawater tem- perature is typically between 34° and 40°F.
Hydrates are members of a chemical class of compounds Hydrocarbon water systems. Hydrates are solids composed of water and a gas (methane, CO,, etc.). The water forms a crystal lattice of cavities with pentagonal and hexagonal surfaces. Each cavity, or cage, may enclose a single mkthane (or other foreign) molecule.
In some ways. hydrates are similar to ice. Hydrates have a density close to that of ice, and have an appearance like frost or ice. However, in contrast to ice, the decomposition temperature of hydrates increases with increasing pressure at pressures below 15,000 psi. A hydrate thermodynamic equilibriumcurve, or decomposition curve, (bold line) for a hypothetical oil/water/gas production system is shown in Fig. 1. The decomposition curve starts at around 100 psi and 34°F and rises to 3,000 psi at around 70°F. Hydrates may form at temperatures below and pressures above the hydrate decomposition curve. Also shown in Fig. 1 is a pressure-temperature profile curve (thin line with arrows) of produced fluids in a flowline from deepwater wells to a shallow water platform 40 to 60 miles away.
DeepStar's Evaluation Of Shallow Water Flow Problems In The Gulf Of Mexico
Authors: Nations Joe F. , Medley George H. 
Published: October 2008

Abstract
The DeepStar Consortium of 18 energy companies is leading the development of new technologies to allow the economic exploitation of deep-water Gulf of Mexico reservoirs. During the past several years, DeepStar's Drilling and Completions Committee has focused on solving shallow water flow (SWF) problems encountered while drilling in deep water. Because the fracture gradient is low at this depth, it is difficult, if not impossible, to drill with enough mud weight to keep the well from flowing, which results in several related problems.
DeepStar has conducted several studies to address this issue. These studies include the development of a SWF database, the investigation and development of polymeric mud systems that can shut off shallow water sands and impair permeability of shallow water zones, research and development of cement slurry designs that are effective in shutting off the annulus to a shallow water flow, unique methods of placing casing seats below water sands, and other studies. These studies have been instrumental in advancing the development of deep-water reservoirs. This paper reviews the results of these studies.

Introduction
The DeepStar Consortium Drilling and Completions committee identified SWF as one of the most imposing problems encountered in deep-water drilling. Shallow water flows, occurring when shallow, over-pressured sands are penetrated, are encountered all across deep-water sections of the Gulf of Mexico. They are most common in water depths exceeding 2,000 feet, and may be found as single or multiple lenses. The sands typically occur at depths below the mud line (BML) of 300 to 2,000 feet, but may occur as deep as 7,000 feet or more BML.
Handling the actual water flow is only one problem as- sociated with these zones. Pore pressure -in these shallow sands is normally very close to fracture pressure. This makes well control very difficult. As the water depth increases, the difference between fracture and pore pressure decreases. The pore pressure gradient remains relatively constant, but the fracture gradient decreases. This has long been recognized, and is well documented Figure 1 illustrates this importantconcept.
Losing circulation makes continued drilling difficult and increases the likelihood of poor cement jobs. In the worst case, if the well is shut in without having sufficient casing set, the resulting formation fracture could broach to the surface3
These over-pressured sands are normally unconsolidated, which exacerbates the problems associated with drilling into a SWF zone. Sand will be produced along with the water. This can result in the accumulation of sand mounds on and around well heads. When the flow cannot be controlled, hole enlargement results. Continued hole erosion may result in subsidence and buckling of one or more casing strings, and the possible loss of the well. The flows have the potential of eroding the soil around the sea floor templates of tension leg platforms with a resultant multi-million dollar loss.
Design, Planning, Implementation & Management of a Multi-Lateral Well on the Forties Field: A North Sea Case History
Authors: Jones R.D. , Lurie P. , Hibbert E.B. , Butler P. , Freeman A. 
Published: October 2008

Abstract
This paper describes the experience and learning gained whilst, designing, planning and installing a Multi-Lateral Well on the Forties field operated by BP Exploration in the UKCS. This project was initiated by the Research and Development groups of BP Exploration and Halliburton Energy Services, and sponsored by the European Union's Joule-THERMIE Program which supports the implementation of technology in Europe. The objectives of the project were to drill and complete a dual lateral well with commingled production, at minimum risk and cost, and to monitor and report the production performance. The difference between this project and the majority of multi-lateral wells drilled to date will be the installation of a cemented junction with connectivity, isolation and re-entry capability. The successful execution of this project will provide the industry with data on the long term performance of a cased hole, cemented, junction design. It will also provide production performance from a dual lateral well and give details of the challenges facing the management of such a well in a mature field environment. It is anticipated that this will lead to increases in the application of this technology, improve the economical recoverable reserves from mature fields and reduce the cost of new fields.

Introduction
Application of multi-lateral wells was limited to wells that did not require through tubing reservoir access for stimulation or water, scale and sand management.
Junction construction advances through system development and testing by Longbottom 1 demonstrated the possibility existed of cost effectively constructing and installing a design which provided isolation, access and connectivity. The experience and learning gained by the implementation of this project, enhances the ability to construct a cased and cemented dual lateral, operate each lateral as a separate well and perform those remedial operations presently available to the industry.
The risk and uncertainty surrounding a project of this nature means that without the support of programmes like THERMIE, initial economics are sensitive when it comes to applying new technology in a mature field environment such as Forties. Remaining well targets are relatively small and production is complicated by demands for sand, scale and water management. In-fill and sidetrack drilling is expected to continue at least until 1999. If the recent success of the in-fill program continues, some platforms will become slot constrained. The application of new technologies, like multilateral wells, are expected to enable more targets to be reached from fewer surface locations. This well is the first step in this new direction.
Design and Analysis of High Temperature, Thermally Insulated, Pipe-in-Pipe Risers
Authors: Delafkaran M. , Demetriou D.H. 
Published: October 2008

Abstract
Bottom tow pipeline bundle installations are gaining acceptance in deepwater developments. This is particularly the case where paraffins and hydrates pose a problem, since insulation and heating lines may easily be added inside the buoyancy casing, with less cost impact than in vessel based methods.
However, barriers to more extensive use of the bottom towed bundle technique are perceived problems of potential leakage into the outer casing and perceived problems related to the pressurization of the casing.
Approaches to mitigation of such problems, such as Bulk heading and foam filling are proposed and evaluated herein.

Introduction
Deepwater developments currently underway are increasingly requiring either insulation or heating to prevent hydrate formation or waxing in flowlines traversing cold ambient waters. Flowlines may be insulated either with directly applied insulation, pipe-in-pipe insulation, or insulation wraps within cased bundles. Heating may be achieved utilizing heating water in separate lines or annular jackets, or electrically, utilizing skin effect current transfer or other means.
Possible installation methods, already in use or imminent, include reeling, J-lay, S-lay or towing of bundled pipelines. In a towed installation, the pipelines and casing are welded into strings on a beach. To date, all Gulf of Mexico bottom towed bundles have been fabricated at Matagorda Peninsula, just down the coast from the mouth of the Colorado River. Thus site accommodates bundles up to 10 miles long. The bundle is then deflected laterally off of the beach and towed to the site. Pipelines may be towed on the sea dace, at mid- depth, or on bottom. All the Gulf of Mexico bundled installations have been by bottom tow.@ The bundled approach to installation of multiple pipelines, is to gather the several pipelines into a single package, and to provide a casing around the entire package which brings the total bundle submerged weight into a desired range. For a bottom towed bundle this submerged weight must be great enough to provide stability during the launch and tow process but low enough to permit towing by available vessels. The casing diameter required for correct submerged weight is normally sufficiently large such that an insulating wrap layer may be added to the flowlines without change in the design of the bundle, and the low density of insulating materials makes only a modest change in the submerged weight.
In shallow water depths the casing may resist hydrostatic collapse through its inherent stiffness, however, as water depths increase the increase in wall thickness required to prevent buckling makes it impossible to achieve a desired submerged weight.
Large Scale Model Testing Of Deep Sea Risers
Authors: Huse E. , Kleiven G. , Nielsen F.G. 
Published: October 2008

Abstract
The paper describes a series of tests with 90 m long models of deep sea risers, performed at an open air test site in a Norwegian fjord. The main purpose of the tests was to provide experimental data for the vortex induced vibrations (VIV) of such risers in a shear current. The test results can also be used to study collision criteria, drag coefficients, etc. The paper concentrates on a discussion of one of the phenomena observed in the tests, the axial vibrations of the risers. A theory for estimating the fatigue stresses due to such axial vibrations, induced by the VIV, is developed and presented in the paper. If the VIV frequency coincides with half the frequency of the first axial vibratory mode of the riser, the theory predicts extreme stresses to occur. The phenomenon of axial vibrations may become an important aspect of future deep sea riser designs.

Introduction
The riser system represents one of the main challenges in the design of safe and cost-effective concepts for production of oil and gas at sites with ocean depth of one to two thousand meters or more. The loads and responses of deep sea risers due to current can to a certain extent be predicted by numerical methods. However, for verification of the theory, and for detecting possible unexpected phenomena or problems encountered when designing for conditions beyond previous experience, model testing is the best, if not the only possible tool. One of the problems in the design of such systems is that there is no model tank: in the world today deep enough to model the complete riser and mooring systems at a scale which has traditionally been considered necessary to achieve reliable predictions. One possibility is to do model tests in fjords or the open sea. In Norway an extensive test program was done in August 1997 at an open air site with 90 m long models of steel risers, at a geometric model scale of about 1:15. The present paper describes the tests and shows examples of results. An interesting aspect of the results was the considerable axial tension fluctuations induced by the vortex induced transverse vibrations (VIV). This triggered the authors to study VIV-induced axial vibrations in deep sea risers in more detail. The results indicate that for steel production risers of the order of 1500 m length the VIV may induce resonant axial vibrations causing such dramatic stresses that it becomes an important aspect of future deep sea riser designs.

Objective
The objective of this paper is to present a recently conducted research project, including a series of model test on deep sea risers, and to show some examples of the results. A main part of the objective is to present the development of a theory for VIV-induced axial tension fluctuations.

Large scale tests

Test philosophy, test site.
Since there are no model tanks deep enough for complete modeling of deep sea systems at what has traditionally been considered a suitable model scale, one has to look for other possibilities.