bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Consistent Procedure for the Estimation of Pseudo-Component Properties
Authors: Leibovici C. F. , Govel P. L. , Piacentino Thomas 
Published: December 2007

ABSTRACT
A new method is presented for the estimation of physical properties of pseudo-components generated by any lumping procedure. Completely consistent with the equation of state to be used for the description of the thermodynamic behaviour of the lumped system, this method tends to minimize the loss of information induced by component lumping. Applied to complex fluids, it has been proved to be very effective. For illustration purposes, some results are reported for a North Sea gas condensate and a Gulf of Guinea light oil.
Reservoir Management at Ekofisk Field
Authors: Christian T. M. , Currie J. C. , Lantz T. G. , Rismyhr O. , Snow S. E. 
Published: December 2007

Abstract
A major field study was conducted to determine future operating strategy for Ekofisk Field. Historical and predicted performance of various IOR processes were evaluated and an IOR process was selected. The evaluation was made in the context of ongoing Upper Ekofisk Formation gas injection and water injection into the underlying Lower Ekofisk and Tor formations. Optimization of the recommended waterflood and studies of other reservoir management concerns are described. The reservoir management strategy was developed to integrate the most economical improved oil recovery process with a strategy to minimize future subsidence.
A Simulation-Based Analysis of Multiseam Coalbed Well Completions
Authors: Young G. B. C. , Paul G. W. , Saulsberry J. L. , Schraufnagel R. A. 
Published: December 2007

ABSTRACT
Reservoir simulation of a coalbed methane field was used to investigate well completion and operating practices in producing gas from shallow, thin, multiple coal seams. Data from a zone isolation packer, which allows production monitoring from individual completion zones, corehole gas contents and bottomhole pressure were used to determine the efficiency of well completions and gas drainage throughout the field. The results show that wells amenable to recompletion can be identified from simulated zone isolation packer measurements; new wells can be located based on the simulated distribution in residual gas content around existing wells; gas recovery is increased by downspacing; and small increases in back pressure can reduce gas recovery.
New 3D Model for Optimised Design of Hydraulic Fractures and Simulation of Drill-Cutting Reinjection
Authors: van den Hoek P. J. 
Published: December 2007

ABSTRACT
This paper presents a three-dimensional hydraulic-fracturing simulator permitting direct input of the expected net pressure at the end of a hydraulic fracture treatment – a parameter that can be readily derived from field measurements. The simulator can thus easily be used at the wellsite to generate field-calibrated fracture geometries and optimised pump schedules. It embodies a twodimensional description of fluid flow in the fracture. Rapid fracture growth (e.g. through negative stress barriers) is handled in a stable manner.
Propagation through layers with different Young's moduli is described using the Barenblatt approach, giving a realistic estimate of containment by modulus contrasts: commercially available models generally overestimate the containment effect. This is of importance for the simulation of drill-cutting reinjection, where stiffness layering may enhance possible containment by soft, permeable sand layers interbedding the thick shales. The model can also handle the continuous stiffness gradient in these shales.
Benchmark comparison with data from the GRI staged field experiment No. 3 shows that the new model compares well with existing models for this case. The performance of the model is illustrated for three field cases. The first case concerns the design of a massive hydraulic fracturing treatment offshore The Netherlands, in a reservoir consisting of five layers with negative stress barriers. The simulator was used to optimise the perforation location and the pump schedule, using an expected net pressure at shut-in of 500 psi. The observed onset of tip screen-out at the end of the treatment suggests that the schedule as it was pumped away was indeed (nearly) optimum. The treatment produced an initial transient productivity improvement factor of about five.
The other two field cases are examples of different North Sea drill cuttings reinjection scenarios. The possible importance of stiffness layering between the thick shales and thin interbedding permeable sands when injecting large volumes (e.g. from a dedicated injection well) is highlighted. The simulator is used to assess the relative merits of intermittent injection with long shut-in intervals (one month) and continuous injection.
Successful Prediction of Condensate Wellbore Behaviour Using an EOS Generated from Black Oil Data
Authors: Furnival S. R. , Baillie J. M. 
Published: December 2007

Abstract
Few, if any, blackoil-type correlations are available for describing the PVT behaviour of Gas Condensates and Volatile Oils. Such near-critical fluids are generally modelled using multi-component Equations of State (EoS). However, EoS require detailed laboratory analyses to be performed on actual reservoir fluids. For modelling production wells, this data is often of poor quality or not available at all.
In a production system, there is usually a regular measurement of the post-separator condensate and gas gravities (stock tank oil and gas) and the total Condensate-Gas-Ratio (CGR). In this study, this data was used to generate a four pseudo-component description that was then used with a conventional EoS to make predictions of fluid behaviour.
The basis for the selection of the four pseudo-components is discussed as is the calculation of the component mole fractions using the two stock tank gravities, the CGR and the additional constraint of the mole fractions summing to unity.
The EoS model was tuned to data obtained from a North Sea Gas Condensate well. The tuned model was then used with an appropriate flow correlation to successfully predict top hole conditions, having specified measured bottom hole conditions.
Four Years' Subsea and Marine Experience With the Ivanhoe/Rob Roy Development
Authors: Smith S. N. 
Published: December 2007

ABSTRACT
This paper presents experience of subsea and marine systems gained from the first four years of production from the Ivanhoe/Rob Roy fields focusing particularly on those areas which are different from a fixed platform development.
As an introduction the overall field layout is described and the success of the development is demonstrated by summarising availability of the facilities. The paper then describes the field development work since first oil, together with the inspection, repair and re-design work that have been necessary to ensure this success. The description includes work on all facilities on the sea bed, work on marine systems, and subsea well servicing. It thus includes the hull, stability and damage stability, bilge and ballast systems, subsea Christmas trees, moorings, flexible risers, flowlines and jumpers, valves, chokes, electro-hydraulic control system, umbilicals, downhole gauges, etc.
The information can be used to lead towards more cost effective developments in the future.
TAME: A New Concept in Water-Based Drilling Fluids for Shales
Authors: Downs J. D. , van Oort Eric , Redman D. I. , Ripley D. , Rothmann B. 
Published: December 2007

Abstract
There is a growing awareness in the drilling industry that many cases of borehole instability may be caused by the changes in shale pore pressure resulting from fluid invasion. A hydraulic pressure differential, arising when the mud-column pressure exceeds the pressure in the shale pore fluids, drives fluid from the wellbore into the surrounding shale and propagates an expanding pressure front. The resulting changes in the effective stresses around the wellbore may then be sufficient to promote rock failure.
A new generation of water-based drilling fluids are being designed to minimise such pressure-penetration effects in pores by reducing either the shale's permeability to aqueous fluids or the rate at which fluids can flow into shales. The new thermally activated mud emulsion (TAME) system, utilising a combination of a surfactant solution and emulsion phases to reduce fluid entry into shales, is one of the first field-tested drilling fluids designed specifically to reduce borehole instability arising from the penetration of pressure into shale pores.
The first prototype TAME system comprises a conventional aqueous KCl-polymer drilling fluid containing a solution of an alcohol alkoxylate additive, components of which can undergo a phase transformation at downhole temperatures to form a fine emulsion. Both the solution- and emulsion-phase elements of the alkoxylate appear to make some contribution towards reducing rates of fluid flow into shales, although their exact mode of action is still unclear.
The prototype TAME system has been successfully field tested during 1992/93 in 17.5", 12.25", 8.5" and 6" sections of five deviated development wells and one exploration well in the UK North Sea. The overall conclusion from this test campaign is that the TAME system is superior to conventional KCl-polymer and polyglycerol muds by virtue of its better borehole-stabilising qualities, higher rates of penetration, significant waste reduction and lower mud time rates (the total time spent drilling on bottom, tripping, conditioning the hole or mud and circulating the mud).
Following these encouraging field tests, TAME formulations have evolved to become Shell Expro's preferred fluid system for drilling reactive shales in standard exploration, appraisal and development wells. Moreover, building on the information obtained from field experience with TAME, even more effective shale drilling-fluid formulations are currently under development.
Maureen Produced Water Injection
Authors: King R. E. 
Published: December 2007

Abstract
This paper describes the application of produced water injection on the Maureen platform to improve the quality and reduce the quantity of water discharged overboard. The production history of the field is reviewed. A number of alternatives considered to resolve the problems associated with increased water production are discussed. Results of a produced water injection trial are presented, together with the performance to date of permanent injection facilities. Future plans are outlined for optimising water management requirements and reservoir pressure support.
Goal-Setting Regulation: Truly Cost-Effective Safety?
Authors: Perham A. J. , Garlick A. R. , Forster J. H. 
Published: December 2007

Abstract
This paper aims to support the Offshore Industry to achieve truly cost-effective safety. It examines the new framework for emerging Offshore Regulations, with its largely "goal setting" approach.
Three main themes are presented: how to understand the HSE's requirements for acceptable Safety Cases; professional project management planning, with "tit for purpose" quantitative risk assessment (QRA) and cost benefit analysis (CBA); and decision support for remedial action plans that are truly cost-effective and reduce risk demonstratably, as low as reasonably practicable (ALARP).
An affirmative answer is given to the question posed in the title, acknowledging the massive efforts being made. Momentum must be maintained and the safety cases put to work, using several recommended steps for future action.
The Ivanhoe/Rob Roy Safety Case Development
Authors: Spittal John 
Published: December 2007

Abstract
The development and submission of installation safety cases is an activity which has and will in the future utilise a significant level of operators' manpower. The Amerada Hess Ivanhoe/Rob Roy fields safety case was prepared and submitted initially to the HSE as an early voluntary submission for a floating production system and then as the formal safety case submission in June 1993.
This paper will detail how the safety case was developed starting from the ‘Forthwith Studies’ defined by the Cullen Report. It will detail the various development stages of the document and the changes that were carried out before a satisfactory format was reached. A particular strength identified in the voluntary safety case was the hazard identification and mitigation section, which also includes the hazard inventory. This section will be presented in detail with examples in some of the main hazard groups, namely (i) loss of containment, (ii) dropped object, (iii) marine impact and helicopter crash, (iv) marine system faults, (v) loss of structural integrity and (vi) environmental hazards. The methods used to firstly identify the hazards associated with the installation, then qualitatively risk rank and finally, perform quantified risk assessment will be presented. Detailed information on the dropped object studies will be specifically highlighted.
This paper will provide an insight into the development of a safety case which has been reviewed by the HSE, as part of the voluntary safety case exercise. The sharing of the Amerada Hess experience will be of great benefit to those involved in the development of installation safety cases, particularly in the area of floating production systems.
Horizontal Drilling with Coiled Tubing: A Look at Potential Application to North Sea Mature Fields in Light of Experience Onshore The Netherlands
Authors: Faure A. M. , Zijlker V. A. , van Elst Herman , van Melsen R. J. 
Published: December 2007

Abstract
Drilling with a continuous coiled string presents an array of opportunities for reducing drilling costs and improving production potential. It offers exciting perspectives for enhanced resource management in established oil and gas provinces.
A Shell operating company recently completed a horizontal sidetrack with coiled tubing onshore the Netherlands. A medium radius horizontal lateral was drilled with a 2-inch coiled tubing. This operation was the first step towards the development of a comprehensive Coiled Tubing Drilling (CTD) system able to re-enter and re-complete wells without conventional rig assistance.
Operations in the Netherlands provided key parameters for evaluation of the potential and limitations of CTD. This experience indicates that CTD is a suitable technology for the optimization of mature North Sea fields. It offers potential cost advantages and should help to maximize hydrocarbon recovery in this area.
New developments are required to meet the challenges of the offshore environment, under-balance operations, short-radius multiple drainholes or through tubing drilling to name but a few. Investments in these directions are well worth while, in view of the opportunities that CTD offers for enhancement of the drilling and production process.
A New Approach to Subsea Oilfield Development Using Innovative ESP Technology
Authors: Simpson A. J. , McKenzie Martin , Robertson M. P. 
Published: December 2007

Abstract
A family of exciting new Electric Submersible Pump (ESP) technologies promises to radically improve the development economics of many oilfields and field extensions. This technology is particularly relevant to prospects in the range 5-100 million barrels reserves, which are located greater than 15 kilometres from existing platforms and often suffer uncertainties on reservoir performance (pressure, sweep, heterogeneities inflow performance etc.). Prospects in that category generally offer mediocre to inadequate economics or unacceptable risks of ‘downside’ potential. Platform development entails untenable capex exposure, whereas conventional subsea development (e.g. by gas lift) will result in very inferior production performance.
The new technologies which ‘unlock’ the economics of such fields are:
Viable subsea ESP technology is available now and will be field proven during 1994/95. Proven high reliability pump systems are now available, underwritten by performance contract. Bottom discharge pump systems offer powered ‘dump’ injection from an aquifer to the oil zone. (This is a particularly efficient way of achieving water injection and obviates the tremendous weight penalty of conventional water injection systems). Tandem pump versions of both conventional and bottom discharge systems offer much higher performance and assure long system life. Multiple pump completions may offer the prospect of the cost effective ‘complete for life’ subsea ESP well in both conventional and bottom discharge mode.
These technologies offer superior technical and economic performance compared to existing, available methods, thus achieving enhanced development economics more robust to reservoir performance uncertainty.
Cost Reduction: Initiative for the New Era
Authors: Spaven P. M. 
Published: December 2007

Abstract
In order to meet the demands of cost-effective new field economics in the next decade, the Industry must generate a new strategy for smaller fields development. The CRINE initiative was first considered in the summer of 1992. This paper will highlight why the CRINE initiative was launched, the methodology being used to identify solutions, and what objectives were set.
Most cost reduction initiatives in the past have been single company activities designed to meet a corporate strategy plan. CRINE has taken a different approach in its use of work groups with selected members from all sectors of the industry. Dissension, self-criticism and team effort is being harnessed to generate new culture for the future. The CRINE Steering Group has set an initial objective of reducing 1992 capital costs by 1/3 within 2 years and by a further 1/3 within 5-7 years.
Modelling Blowout Control by Means of Downhole Kill Fluid Injection
Authors: Oudeman Pieter , Baaijens M. N. , Avest Dick ter 
Published: December 2007

SUMMARY
Blow-outs happen very infrequently nowadays, thanks to strict well-control procedures and improved drilling equipment. When they do occur, control over the well can usually be regained rapidly after capping. In certain cases, it may be necessary to kill the well after a blow-out by injecting kill fluid through a relief well. The simulator described in this report predicts the sequence of events during such operations. Study of the sensitivity of simulation results to variation of input parameters provides a basis for optimal design of relief wells and optimal choice of kill procedures.
Optimisation of the Return Gas Distribution During Kicks in Oil- and Water-Based Muds: Results From Full-Scale Kick Experiment
Authors: Rommetveit Rolv , Hovland Frank , Olsen T. L. 
Published: December 2007

ABSTRACT
A number of gas kick experiments have been performed in a 2000 m long, 60° inclined research well. During the experiments a several of parameters were varied, such as mud density, mud type, gas concentration, and control rate of the kick. The well was heavily instrumented during the experiments, both downhole and surface.
The gas distribution at start of the kick has been computed, and compared to the gas distribution out of the well which was calculated based on, measurements of the mixture density through the choke line, choke pressure and pit gain. This was done for the majority of the 24 kicks which were performed. The effect of mud density and solubility on the return distribution has been analysed. Effects of operational procedures during the kicks have been analysed as well (circulation rates and duration of close-in).
The work shows that the return gas rate and gas distribution depends on the following variable; the initial gas distribution, mud type (OBM or WBM), and operational history of the kick.
Optimal operational control procedures which will create the most favourable return gas distribution are recommended.
A System Approach to Annular Control for Total Well Safety
Authors: Leismer Dwayne 
Published: December 2007

ABSTRACT
In the event wellhead integrity is lost, the uncontrolled flow of hydrocarbons could risk life, property and the environment. To prevent this risk subsurface safety valves can be used to control the well below the wellhead. Conventional surface controlled subsurface safety valves (SCSSV) are used to control the production tubing. However, often the annular space between the tubing and casing contains large quantities of gas directly below the wellhead1. An annular control (AC) safety valve is a surface controlled subsurface safety valve which allows annular flow when open but provides a barrier below the wellhead when closed. When the AC safety valve is used with a conventional SCSSV it can provide overall well safety.
The scope of this paper is to identify, review the design and summarize testing of the components that comprise an annular control safety system.
The Development and Application of a Slickline Retrievable Bridge Plug
Authors: Gee Nicholas , Brown Sam , McHardy Colin 
Published: December 2007

ABSTRACT
The development of through-tubing retrievable bridge plugs suitable for the monobore type completions favoured in the North Sea provides a clear example of completion manufacturers fulfilling a need created by Operating Company requirements.
The development and initial field application of a slickline retrievable bridge plug is described, illustrating the innovations inspired both by the Operating Companies technical leadership and the drive toward cost efficiency in well operations.
Everest and Lomond Completion Design Innovations Lower Completion and Workover Costs
Authors: Laing C. M. , Ogier M. J. , Hennington E. R. 
Published: December 2007

ABSTRACT
The completion design and perforation operations for the Everest and Lomond gas condensate fields incorporated several significant innovative features. These resulted in reduced rig time requirements, quicker access to sales gas and lower operations costs. Future benefits will include better well performance and reduced well workover and repair costs.
Current Fiscal Problems in the UKCS
Authors: Kemp A. G. 
Published: December 2007

ABSTRACT
The 1993 budget has dramatically changed the fiscal situation applied to petroleum exploitation in the UKCS. The changes substantially impact on all aspects of the upstream business.
On existing producing fields and those under development there is a marked positive effect on industry net cash flows from the reduction in the rate of Petroleum Revenue Tax (PRT) from 75% to 50%. On discoveries not yet developed the abolition of PRT does not change the effective tax take on production income on the majority of fields as the existing allowances already provide effective tax shelter. On the large fields the tax take can go down substantially. On the other hand the net of tax appraisal costs on new prospects increase fourfold.
The post-tax returns on incremental investments in mature fields are increased significantly by the reduction in the PRT rate.
The removal of the PRT crossfield allowance for exploration and appraisal clearly has an adverse effect on exploration incentives, but the fiscal situation facing an explorer is now very simple, and the level of tax take very low by international standards.
The imposition of the Gas Levy and PRT on new gas contracts or on incremental investments in mature gas fields can readily render such projects non-viable. The precise impact of PRT depends critically on what PRT volume allowance is available for the project in question.