bluuebunny/crossref_metadata_2025_split huggingface dataset:
Expected Evolution in the Prices of Fuels for Electricity Generation in Argentina
Authors: Bravo Victor , Kozulj Roberto 
Published: December 2007

Abstract
One of today's great mysteries is the future evolution of the price of fuels for the generation of electricity. This is due both to the uncertain evolution in the price of oil and oil byproducts and to the impact of deregulation in the price of natural gas at wellhead in the medium and long term, as well as to fluctuations in the supply price of electricity within a deregulated and diversified system such as the Argentine one. The present work delves into these matters and provides a joint forecast of the price of the main fuels for electricity generation under different hypothesis combinations. At the same time, it includes a brief analysis of the repercussions which a price increase of natural gas at wellhead would have on electricity costs and contrasts such forecasts with those arising from different supply scenarios, referring the analysis to average annual monomial prices from the wholesale electricity market.
Furthermore, limitations are pointed out as regards information and methodology limitations to carry out forecasts with predictive rather than informative value, notwithstanding the inclusion of means to deal with uncertainty.
The natural gas composition in transport by pipelines
Authors: Casares Carlos A. M. , Lanziani José Luis 
Published: December 2007

Abstract
The design and operation of a gas pipeline requires, as a rule, considering the composition and average specific gravity of the gas already transported or to be transported.
Now the truth is that such gas will not always have the same composition or specific gravity, given the fact that it varies significantly from winter to summer, and that it can even change along the pipeline.
This paper was done with the intention of showing the effects that those changes can have in transportation capacity, power used and in transported energy. In order to do so, we based our study simulating Steady-Flow conditions and considering extreme situations.
The basic principle "equal transported volume does not imply equal transported energy or equal mass" was a clear evidence in our study, and in some cases the differences were significant.
At the same time this is particularly important because we can appreciate the implications of using commercial criteria indistinctly, for instance the sale of energy volumes, transportation of mass volumes or design criteria.
The main objective of this paper, then, is to learn about natural gas composition -as far as transportation is concerned-both for the design and operation of a pipeline.
The Prado Basin Oil Wells: A Case History
Authors: Hesson Bruce H. 
Published: December 2007

Abstract
In 1941, the Prado Dam was built in Riverside County, California, near the City of Corona. In 1965, one federal and one private lease were granted for oil and gas exploration behind the dam. The federal lease stipulated that "…all rights under this lease are subordinate to the right of the United States to flood and submerge the lands, permanently or intermittently in connection with the operation and maintenance of the Prado Flood Control Basin Project."
Thirteen oil wells were drilled and completed on these two leases and oil and gas were produced in the field from 1965 through 1993. During this period, the wells were submerged numerous times and several oil spills occurred. After an oil spill in 1993, the wells were shut in by a court order. In addition, California Department of Conservation's Division of Oil, Gas, and Geothermal Resources (Division) issued a formal order outlining corrective action to be taken by the operator to prevent another spill. The operator failed to comply with this order. To prevent another spill, the Division undertook remedial action over a three-year period. Finally in 1996, the wells were plugged and abandoned when the operator failed to comply with the formal order and it was determined the wells were an environmental hazard.
Waterflood Optimization Using a Combined Geostatistical – 3D Streamline Simulation Approach: A Field Example
Authors: Spath Jeff , McCants Steve 
Published: December 2007

Abstract
Stochastic reservoir description techniques are combined with a three-dimensional streamline simulator to optimize volumetric sweep efficiency in a mature, West Texas waterflood. Results from the streamline model were validated using an IMPES, finite-difference scheme. It is shown that the combination of multiple-realization property distribution with an efficient streamline model is an attractive alternative to the traditional, finite-difference approach. Performance predictions are made for the placement of new infill wells (vertical and horizontal) and for pattern modification by selectively shutting in existing injectors.
Geostatistical techniques including kriging and cokriging are used to generate realizations of property distributions. Fundamental to the geostatistical techniques described is the honoring of hard data and we illustrate the importance of integrating various data sources to constrain these techniques. Specifically, production, core, log, pressure transient, geological and 3D seismic data were combined to estimate near-well properties and to place realistic constraints on distributing porosity, permeability and net-to-gross thickness.
The advantages and the applicability of the streamline approach are outlined as well as the caveats. Primarily, it was found that streamline simulation is much more efficient in solving two-phase, immiscible problems and produces results equivalent to finite-difference methods.
Cut-off or Separation? A New Approach to Distinguish Reservoir Rock from Non-Reservoir Rock for Reservoir Modeling and Simulation
Authors: Li Dachang , Dria Myra A. 
Published: December 2007

Abstract
The term ‘cut-off’ refers to a joint effort by geoscientists and engineers to define a value which discriminates non-reservoir rock (shale) from reservoir rock (sand), and has been used in the petroleum industry for several decades. In many instances a single cut-off is not good enough to define sand requiring the use of additional variable cut-offs. The determination of cut-off(s) is highly dependent on a geoscientist's or engineer's experience. There exists no well-defined method that is built on a sound scientific basis.
A systematic method is presented in this paper. The new method separates reservoir rock from non-reservoir rock based on the statistical properties and probability distribution functions derived for the various properties of a reservoir interval. It is common that the histogram of a variable (i.e. porosity) has a mixed interval between reservoir and nonreservoir rocks.
No matter how a cut-off is defined on the histogram, there will always be a number of values that are incorrectly classified. As a result, we have seen errors in hydrocarbon volume calculation which have been in the range of 5 to 30 %. Unlike the typical application of cut-offs, the proposed method identifies a boundary (no or little mixing) between the two rock populations and then separates them based on this boundary. Correct boundary identification, by analyzing all available variables collected from well logs, is the key to success. When there is no clear boundary, integration of engineering data (i.e. relative permeability and capillary pressure) with the well logs helps to identify possible boundaries or cut-offs.
A field study demonstrates the principle of the new method and the improved results includes more than 80 wells. The method is easy to understand and to apply in practice.
Coiled Tubing Drilling Case History, Offshore The Netherlands
Authors: Gunningham M.C. , Coe B. , Evans S. , Wiersma J. 
Published: December 2007

Abstract
This case history outlines a recent coiled tubing (CT) drilling project in the Dutch Sector of the North Sea. Operations were conducted from a jackup drilling unit. The drilling unit conducted preliminary operations, commenced the sidetrack and recompleted the well. CT was used to drill the reservoir section of the new hole.
For CT, the objective was to exit through the 5-in. liner shoetrack and drill 230 ft of a 3 3/4-in. directional hole. The surface equipment had been designed to allow for the CT to be stripped out of the hole if substantial drilling fluid losses occurred. In this case, the well would be cleaned up and tested and the 3 3/4-in. section left barefoot. In the event that drilling fluid losses did not occur, then the section would be drilled overbalance with a low toxicity oil-based mud (LTOBM) and a 2 7/8-in. slotted liner deployed.
The 5-in. shoe track was cleaned out successfully with a mill and a positive displacement motor. The 3/4-in. hole section was drilled from 12,276 ft to the required total depth at 12,486 ft in 33.5 hours with one bottomhole assembly (BHA) and bit.
This case shows that with the proper planning, detailed design and execution, CT drilling can provide a cost effective alternative for drilling sidetracks.
An Operational Overview of the Use of High Pressure Coiled Tubing in the Gulf of Mexico
Authors: Larsen Henrik Aslak 
Published: December 2007

Abstract
Coiled Tubing (CT) has successfully been utilized to enter wells in the Gulf of Mexico (GoM) with well head pressures up to 7500 psi. Several different applications has been applied to high pressure wells, thereby yielding savings to the operators and increasing the operational safety. The equipment is presented along with the CT material selection. The business mix and operational statistics are presented and discussed.
Utilizing Coiled Tubing in Mobile Bay's 22,000 TVD Gas Wells Yields Economical and Technical Advancements
Authors: Larsen Henrik Aslak , Kenrick Anthony , Bell Robert 
Published: December 2007

Abstract
It is desirable to pursue the coiled tubing (CT) as an alternative to snubbing in performing through tubing work over operations. With the advances in high pressure CT, it is feasible to contain high pressures. High yield strength (100,000 psi) coiled tubing material has allowed for coiled tubing intervention in the Mobile Bay Norphlet completions. These wells are approximately 22,000 feet vertical depth, high pressure, Hydrogen Sulfide (H2S) gas wells.
The operations performed include:A scale clean out to approx. 22,000 feet.A HCl acid job has been performed at 415F.Clearing a safety valve from build up.
The first operation performed was a scale clean out to 22,000 feet utilizing a spiral wash tool. The well was killed with a 10 ppg NaBr and the same brine was used for clean out fluid. Cost savings of 60% were realized.
The second operation was a HCl matrix acid job performed at 415F.
The third job was a scale clean out across the down hole safety valves. The safety valve was blocked by scale build up and was rendered inoperative. Remedial work was needed. If the through tubing work over did not work, a rig work over was needed. The safety valve was cleared of debris in one operational day. It is estimated that the CT operation cost less than 5–10% of a rig work over.
Positive Displacement Motor Test with Two-phase Flow
Authors: Li J. , Tudor R. , Cox R. 
Published: December 2007

Abstract
Underbalanced drilling with coiled tubing requires the use of a positive displacement motor (PDM) to drive the drill bit. Motor performance characteristics are essential to ensure drilling success and efficiency, and the pressure drop across the motor must be specified to accurately simulate underbalanced conditions at bottom hole. In this study, five positive displacement motors were tested under a variety of mixed ratios of nitrogen and water and different back pressures. The experimental results in this study show that the performance of PDMs powered by commingled fluids is different from water baseline tests. With the commingled fluid at the same effective flow rate, the outputs of torque and mechanical power and the pressure drop across the motor are lower than those for a water baseline test. The torque output is more sensitive to the water rate, while the RPM is more sensitive to the nitrogen rate. It was also found that back pressure has a significant impact on the performance of a PDM for commingled fluids. A higher back pressure results in a lower output of torque, mechanical power and pressure drop across the motor for constant of N2 and water rates.
Using 3D Geological Modelling and Connectivity Analysis to Locate Remaining Oil Targets in the Brent Reservoir of the Mature Brent Field
Authors: Abbots F. V. , van Kuijk A. D. 
Published: December 2007

Abstract
As part of the drive to locate remaining oil targets in the Brent Field prior to depressurisation1, full-field 3D static reservoir models for the main Brent Field (excluding the fault-scarp degradation area called the ‘slumps’2) were constructed last year. Both the Brent Group and the Statfjord Formation reservoirs were modelled using the Shell proprietry 3D geological reservoir and property modelling program known as GEOCAP'J. This paper briefly outlines the approach taken in the GEOCAP modelling of the Jurassic Brent Group Ness reservoir, which formed the basis for the first test-case application of a new well-clustering technique, CRF (Cumulative Resistance to Flow) which is the focus of this paper.
The CRF module is one of the latest technological enhancements of GEOCAP, developed by RTS (Shell International Research and Technical Services, Netherlands). It is a permeability-distance based well-clustering module, that calculates connected reservoir volume to perforations, using the GEOCAP 3D permeability models. Subsequent removal of these connected rock-volume clusters from the model, results in a 3D model of unconnected reservoir volume. The model can then be used to identify unconnected areas that are large enough to be considered as potential remaining oil targets. These areas then warrant further investigation as potential target locations, most importantly in terms of dynamic reservoir modelling aspects, and calibration with latest surveillance data.
The results indicate that there are still several sizeable ‘targets’ (in excess of 1 MMbbls STOIP) left in the Ness reservoir after the currently planned wells have been drilled and these are currently undergoing independent review.
The Gjallar Ridge in the Vøring Basin, NOCS: A Deep Water Challenge in a Frontier, Igneous Influenced Area
Authors: Granholm P. G. , Horstad I. , Larsen D. O. 
Published: December 2007

Abstract
The Gjallar Ridge Licence (PL 215) operated by Saga Petroleum is located in the western part of the Vøring Basin more than 350 km from the Norwegian coastline. The water depth in the licence is 1250-1400 metres. The nearest exploration wells in the area are located on the Nyk High 90 km to the east (drilled by BP in 1997) and two wells on the Utgaard High some 100 km to the east (Figure 1). The frontier nature of the area is reflected in large uncertainties and differences in the geological models proposed for the region.
To focus on the various aspects of the petroleum system in the Vøring Basin it was deemed necessary to instigate a series of regional geophysical and geological studies, in addition to detailed studies of a more localised nature. This was done to address trap formation and petroleum charging as well as the local influence of magmatic intrusions.
A 1600 km2 3D was shot in 1996 and the first exploration well is planned drilled in 1998 (Figure 2).
An Estimate of the Cumulative Environmental Effects of the Disposal in the Deep Sea of Bulky Wastes from the Offshore Oil and Gas Industry
Authors: Picken Gordon , Curtis Tim , Elliott Alan 
Published: December 2007

Abstract
This paper presents an assessment of the potential cumulative environmental effects of the deposition at the North Feni deep sea disposal site of 24 of the steel platforms presently located on the UKCS. It is argued that justification for deep sea disposal could only be made if it were possible to demonstrate significant benefits in terms of reduced risks to persons during the decommissioning process. If large steel jackets could be toppled and transported in the water in one piece, and then released at the deep sea site, this would, it is suggested, reduce the risk to personnel who would otherwise be engaged in underwater dismantling and lifting operations. Candidate structures were therefore identified as those that weigh more than 10,000te in air (the maximum single lift capacity of present heavy lift vessels), and stand in water more than 100m deep (thus permitting toppling of the whole structure under present IMO guidelines). If these structures were deposited at North Feni over a period of about 24 years, the main potential source of cumulative effects would be from the release of contaminants as the sacrificial aluminium anodes were depleted. It is estimated that some 10,700te of anodes would be deposited, giving rise to a peak daily wastage rate of 1,400kg. A modified advection/diffusion model was used to predict the possible dispersion of the dissolved contaminants away from the site of deposition on the seabed. It was concluded that the peak concentrations of all contaminants in the water column extending from 0m to 20m above the seabed would be very low, and would not exceed the coastal Environmental Quality Standard (EQS). Concentrations in the water column from 20m to 40m above the seabed would be an order of magnitude less than those found near the seabed.
Gannet E: The World's Longest Subsea ESP Tie-Back
Authors: MacFarlane J. S. 
Published: December 2007

Abstract
Gannet E is a 20 API crude reservoir located 14 km away from the Gannet A platform. Reservoir properties make artificial lift essential to produce the fluids back to the platform. During conceptual design an ESP was selected as the chosen option due to uncertainties surrounding reservoir and fluid characteristics. Subsea ESPs are in operation elsewhere in the world (Petrobras Carapeba and Amoco Lihua), but these are in close proximity to the processing platform. The 14 km distance of the Gannet E field from the Gannet platform introduces some major technical challenges into this subsea ESP installation. ESP reliability has been poor in the past, and, when combined with a subsea installation, this can become a major Opex burden. To avoid this the Gannet E project established a project goal of achieving a two year run life from the first pump. This paper discusses how the project team addressed the technical challenges of the project, and gives feedback on progress achieved since start of production in July 1997.
Subsea Electrical Submersible Pumps At Large Step-Out Distances
Authors: Al-Mashgari Ahmed , Breit S. , Christmas Dave , Leslie Dave , Smith John 
Published: December 2007

Abstract
As the main reservoirs get depleted, operators are looking increasingly into the satellite fields that hold oil but in quantities that would not justify building a dedicated platform.
Consequently, methods of extracting the oil from these reservoirs by using existing facilities have been investigated. One of the most viable options is to utilize the existing mother platforms to accommodate all the topside electrical equipment, and extend cables up to a distance of 30 kms to the wellheads.
The purpose of this paper is to illustrate the work done by Reda in developing a computer software model to simulate the complete electrical system, and thus predict any problems that might be encountered in a real system. The model was verified by practical data obtained from tests conducted in the Reda, Inverurie (Scotland) and Reda Bartlesville (USA) facilities.
The program was designed to simulate various variable speed drive (VSD) power sources and model the effects of different lengths of cable to determine what combinations of VSD, cable parameters and downhole motor operating conditions would have on the total harmonic distortion.

Introduction
With the cost of intervention of an electrical submersible pump (ESP) reaching 5.6 million US dollars, weather permitting, and reliability still being an issue, operators are interested in ensuring that all possible scenarios that could be encountered are investigated in advance of installation.
One of the main concerns are the ever increasing levels of electrical Harmonics in the system due to the nature of the electrical systems.
Before we progress further it is worthwhile mentioning the four main factors that determine the life of the motor. These are:-The ambient temperature of the produced fluid.The composition of the produced fluid in terms of its capacity to carry heat away.The velocity of the produced fluid past the motor.The level of losses within the motor.
It is clear that temperature is a critical factor as it has direct impact on the insulation, and it is generally accepted that the insulating material is an exponential function of winding temperature. P. 475^
Tern Optimiser Project - The World's First Offshore Closed Loop Optimiser
Authors: Purves B. , Mortimer A. S. 
Published: December 2007

Abstract
The world's first closed loop optimiser on an offshore platform has been installed on Shell UK Exploration and Production's Tern platform using MDC Technology's RTO+ real time modeling optimisation product. The project audit has shown that the benefits are equivalent to 2.5% accelerated oil production. These benefits are made up of 1.5% already achieved from the on-line optimiser and a further 1.0% expected from off-line optimisation.
How Well Connected Is the Schiehallion Reservoir?
Authors: Richardson S.M. , Herbert N. , Leach H.M. 
Published: December 2007

Abstract
The Schiehallion field lies in water depths of up to 500m and is situated on the United Kingdom continental shelf some 200km west of the Shetland Islands. The reservoir was discovered in 1993 and has been appraised with five wells. Development of the field was sanctioned in 1996, development drilling began later that year, and first oil is expected in 1998. During 1995, an extended well test (EWT) was conducted at well 204/20–5. This well was drilled horizontally through the T3la formation, which is composed of a sequence of channel sand bodies which have variable thickness and quality. The purpose of the EWT was to test the connectivity of the reservoir.
Initial transient analysis and reservoir simulation of the EWT suggested that the overall pressure behaviour was close to 'infinite acting', and no reservoir boundary effects were evident. This suggested that the well was accessing a larger connected volume than indicated by the seismically derived thickness and structure maps. Recognising that this interpretation was difficult to reconcile with the static data, the reservoir development plan positioned injector and producer locations in a manner robust to a range of reservoir connectivity outcomes.
This paper describes the objectives, conduct and initial interpretation of the EWT. It then goes on to describe how an alternative explanation of the EWT behaviour was derived by considering the potential uncertainties in the PVT data, and the results from the ongoing development well data acquisition programme. The revised interpretation requires less connected volume than the first, but the overall reservoir development philosophy of targeting producers into the main channel sands remains sound.

Introduction
The Schiehallion field is one of the largest oil fields to be developed on the United Kingdom continental shelf in the past ten years with mean recoverable reserves of 340 MMstb. It is the second development west of Shetland following the Foinaven Field, and is located approximately 200km west of the Shetland Islands in water depths of 300 to 500m (Fig. 1).
The Schiehallion accumulation was discovered in late 1993 by well 204/20-1. Oil is trapped in submarine slope reservoir sands of Palaeocene age. The discovery well identified an oil-water contact at 2064m TVDss. P. 603^