bluuebunny/crossref_metadata_2025_split huggingface dataset:
A New Approach for Economic Evaluation of Horizontal and Vertical Wells in A Sensitive Formation
Authors: Permadi A. K. , Permadi P. , Pamungkas J. 
Published: December 2007

Abstract
Severe formation damage in horizontal wells has been frequently reported. Many theoretical works related to this subject have also appeared in the literature. This indicates that such damage is a serious problem that can considerably affect the economics of horizontal well applications. The purpose of this paper is to present a new approach for evaluating the economic advantage of a horizontal well as compared to the vertical well case in a sensitive formation.
The new approach employs concepts of production loss analysis and the maximum cost ratio (MCR), respectively, to evaluate short and long term production and economic performances. MCR here is defined as the ratio of horizontal-to-vertical well drilling and completion costs arriving at the ratio of net present values of 1.0.
Results demonstrate that, although production performance of a vertical well is generally more sensitive to formation damage, the production loss can be much higher in the horizontal well causing a considerable economic loss when converted to dollars. Based on the analysis of MCR, it is found that (1) the costs limit of a horizontal well is controlled by the degree of damage severity, permeability, and oil price and (2) MCR is well correlated with the standard economic criteria as well as the production performance. In general, the costs limit decreases with damage severity and oil price and as reservoir permeability increases. Overall, the approach proposed can be used as a valuable tool for the economic analysis and provides engineers guidance for optimizing the drilling and completion design when a horizontal well project must go on.
Near-Wellbore Halo Effect Resulting from Tip Screenout Fracturing: Its Direct Measurement and Implication for Sand Control
Authors: Upchurch E. R. 
Published: December 2007

Abstract
This paper presents the findings of an investigation to determine whether or not a near-wellbore "halo" is generated during the process of fracture stimulating a well in a soft, unconsolidated formation. The investigation delves into whether net-pressure generation has any effect on the halo’s formation and, finally, whether the halo could be utilized by petroleum operators as an inexpensive way to control formation sand production.
The results from 4 fracture stimulations in perfectly vertical wells are the primary data used in this investigation. In each case, all necessary steps were taken to ensure that the collected data would show conclusively whether or not the halo occurred and, more qualitatively, to what extent a significant net-pressure increase (resulting from a tip screenout) affected the halo’s formation. All data presented here resulted from direct downhole measurements, either by bottom-hole pressure gauges or by specialized azimuthal GR logging tools that can directionally measure gamma ray intensity.
To date, the possible existence and benefit of the halo has been a topic of conjecture. This study represents the first attempt at directly confirming the existence and extent of the halo under actual downhole conditions.
The Nominal Sand Control Screen: A Critical Evaluation of Screen Performance
Authors: Underdown D. R. , Dickerson R. C. , Vaughan William 
Published: December 2007

Abstract
Over the past few years, several "premium" sand control screens have been introduced into the market. The proliferation of new screens has raised questions about how to choose the proper sand control screen for a particular formation. In order to address this concern, a project was initiated at Chevron to devise a method to evaluate sand control screens.
As a result of this program, a method has been standardized for the evaluation of sand control screens. The method known as the Screen Efficiency Test shows the relationship between the normalized sand control characteristics (i.e., Sand Control Factor) of the screens and the normalized length of time it takes a screen to plug under a certain set of conditions (i.e., the Performance Factor). The results of Screen Efficiency tests to evaluate several sand control screens for a North Sea and West Africa field are discussed in the paper.
The data in this paper also documents that the numerical rating given the screens by the manufacturers are generally not very useful in understanding the sand control rating of the particular screen, or comparing screens from different manufacturers. In addition, the effect of particle size distribution and sand concentration on the relative performance of sand control screens was demonstrated.
Transient Pressure Solution in the Presence of Pressure Drop in the Wellbore
Authors: Ding Y. 
Published: December 2007

Abstract
Horizontal and multi-lateral wells are increasingly used in reservoir engineering to improve the oil recovery. To optimise the efficiency of these wells, it is necessary to develop semi-analytical methods which are simple, fast and accurate, to study the transient pressure behavior. Moreover, the pressure drop in the wellbore, which has sometimes a strong impact on the pressure transient behavior, has to be incorporated in the modelling.
In this paper, the boundary integral equation, based on single layer heat potential, is used at the wellbore boundary to describe the transient phenomena. The pressure drop along the well length is considered. The Galerkin type approach is used to solve the boundary integral equation. Using linear Galerkin approach allows to give good approximation for the extremity effect, especially in the presence of the pressure drop in the wellbore. The pressure drop along the well length can be quickly and accurately evaluated using the linear Galerkin approach then using the commonly used line source method. The implicit Newton's technique is discussed to solve the nonlinear flow equation in the wellbore. The proposed method can be used to study the pressure solution for any number of multilateral wells, as well as selectively perforated wells.
A New Formulation for Simulating Near-Miscible Displacement Processes
Authors: Zhou Dengen , Jensen Clair , Tang Ray , Arif Hozef 
Published: December 2007

Abstract
Gas injection processes are most efficient at miscible/near-miscible conditions. Simulating such processes accurately is a challenge in terms of computer power and numerical stability. Recent advances5–10 in gas injection research suggest that a few key tie-lines, as determined from the phase behavior of the system, control miscibility development. The properties of gas and oil at the displacement front can be directly determined from the phase behavior of the system. Consequently, we propose a new Todd-Longstaff (T-L) formulation for simulating miscible/near-miscible displacement processes based on this recently-developed concept. The new formulation requires specification, at the displacement front, of the hydrocarbon phase densities and viscosities, and the gas saturation as a function of pressure. These properties are obtained from the key tie-line composition and pressure information. This use of key tie-line properties enables accurate definition of the fluid properties and miscibility of the system without using any empirical parameters.
Comparison of the new formulation with a fully implicit compositional model shows excellent agreement, for continuous gas-injection process 2D models used for the Rangely Field. Excellent agreement was obtained between the new formulation and the compositional formulation for continuous gas injection processes. The new formulation not only matches the oil production rates, gas/oil ratios and reservoir pressures, but also matches the saturation distributions that are often more difficult to obtain. The new formulation can be easily implemented by modifying an existing T-L formulation.
NGH on FPSO - Slurry Process and Cost Estimate
Authors: Gudmundsson J. S. , Andersson V. , Durgut I. , Levik O. I. , Mork M. 
Published: December 2007

Abstract
A hydrate slurry process is being developed for capturing associated gas on FPSO's. Natural gas hydrate contains 180 Sm of gas per m3 solid hydrate. It is this property that makes hydrates attractive for storage and transport of natural gas. Hydrate mixed with crude oil and refrigerated to -10 C remains stable at atmospheric pressure, for practical purposes. A capital cost estimate for a FPSO-based hydrate slurry process was carried out for 1,440,000 Sm3 associated gas and 16,000 Sm3 crude oil. The marginal capital cost was 160 million US dollars (the hydrate process only). The cost estimate was expanded to a hydrate slurry chain consisting of FPSO-based production, shuttle tanker transport and land-based receiving teminal. The hydrate chain consts were compared to transporting natural gas by a subsea pipeline. It was argued that hydrate slurry technology should be used for distances greater than 220 km.
Effect of Flow Through a Choke Valve on Emulsion Stability
Authors: van der Zande M. J. , van Heuven K. R. , Muntinga J. H. , van den Broek W.M.G. T. 
Published: December 2007

Abstract
When oil is produced under high water-cut conditions, oil in water emulsions can be formed. The break-up of oil droplets predominantly takes place in the choke valve. We have conducted laboratory experiments to investigate the effect of flow through a choke valve on the oil-droplet-size distribution in the emulsion. In these experiments the choke is modeled as a circular orifice in a pipe. The droplet sizes after break-up can be correlated to the mean energy dissipation rate per unit mass in the orifice. The experiments have been conducted with two set-ups on a different scale. The relation, which we have derived for the maximum stable droplet diameter downstream of the orifice can be applied to both scales. Furthermore the effect of oil viscosity on the droplet sizes after break-up has been investigated.
Quantification of Various Factors Affecting Emulsion Stability: Watercut, Temperature, Shear, Asphaltene Content, Demulsifier Dosage and Mixing Different Crudes
Authors: Kokal Sunil , Al-Juraid Jamal 
Published: December 2007

Abstract
This paper discusses problems related to emulsions that have been encountered in a large Saudi Arabian field. This is a unique field lying both onshore and offshore and is producing from seven different reservoirs. These oils range in viscosities from 2 cP to over 10 cP (@ 22°C) and API gravities range from 28 to 40. The n-pentane asphaltene content varies from 0.2% to over 7% and watercut for producing wells ranges from dry wells (0% watercut) to over 70%. These properties provide an interesting case of operational problems in oil-water separation. The problems include increased incidents of shorting in the separator, tripping of equipment and increased demulsifier consumption.
This paper presents the results of a comprehensive study that was initiated to understand the main causes of emulsion formation in the field. The factors investigated were watercut, temperature, shear, asphaltene content, demulsifier dosage and mixing different crudes. These factors were quantified with a new water-oil separation index that was developed to measure emulsion stability. The results show a strong correlation of asphaltene content in the crude oil with the water-oil separation index or emulsion tightness. Photomicrographs of high asphaltenic crude oil also shows the presence of organic particulate and a generally lower water drop size. These emulsions were videotaped at high magnification using a novel flow-through cell and the visual information has helped our understanding of how emulsions are stabilized by the organic films or "skin" on the water droplets. Recommendations are made for reducing and optimizing demulsifier dosage by adding chemical additives. Many lessons learned are applicable to any crude oil treating facilities.
Inflow Fluid Typing in Screened Horizontal Completions Using a Pulsed Neutron Holdup Imager
Authors: Maher Tom , Trcka Darryl 
Published: December 2007

Abstract
In order to determine if the current well placement was effectively draining the reservoir, a logging program was initiated in a horizontal well completed with a pre-packed screen using conventional production logging, pulsed neutron capture, and pulsed neutron holdup logging instruments. The objective was the monitoring of depletion and the identification of produced fluids along the wellbore. The logging results showed adequate reservoir drainage and suggest that the presence of the pre-packed screen may, under certain conditions, assist in the identification of produced fluids by pulsed neutron holdup imaging.
Production Logging Problem Description in October Field, Gulf of Suez
Authors: Ibrahim Adel A. , Mostafa Azzam 
Published: December 2007

AbstractProduction Logging Tools have significantly helped reservoir management in October field. Direction of water movement within the Nubia reservoir was understood by production logging indicating an active water rise as the primary driving mechanism. Over 100 PLT logs (PLT's) completed on 74 wells in October field have been selected for this study. A computer program is developed to analyze these PLT's systematically with the possibility to correlate the results to corresponding measured data when available. These PLT's were utilized to control water production by identifying proper placements of Through-Tubing Bridge Plugs (TTBP) for water shut-off (WSO).In special cases, when water cut increases, old PLT data can be used to estimate the progress of zone water out without running an additional PLT. This article describes a technique to re-allocate the production within wells based on previous PLT data from the same well. Based on the success of this back-calculation method, over $25,000 per WSO in October field has been saved by eliminating an additional PLT.Experience in October field indicates that results of production logging analysis using conventional tool configuration are not sufficient to make decisions for WSO work over. Well head measurements, reservoir driving mechanism, and direction of fluid movement should also be utilized.Direct PLT interpretation has led to non-representative results for over 78% of the studied wells. The standard PLT analysis usually shows a misleading water production within the different sets of perforations along the well. This problem was first recognized by WSO results through which water was proven to enter the well from the bottom interval only. These errors were first attributed to hole deviation, however, field scale investigation indicated that other factors are involved since the problem was encountered in vertical wells as well. Gradio-manometer's poor accuracy is believed to be the main reason for such non-representative results.
Breaking of a Paradigm: Geology Can Provide 3D Complex Probability Fields for Stochastic Facies Modelling
Authors: Massonnat Gerard J. 
Published: December 2007

Abstract
Stationarity of the random function is the key property of stochastic models to the extent that wrong hypotheses could lead to very unrealistic reservoir modeling for flow simulations.
When non stationarity is suspected at the scale of the domain to be modeled, geologists usually propose either geological drift or seismic attributes to constrain stochastic models.
However, in both cases, confidence in the soft data is limited by the rough aspect of the trends from geological input, the scale problem, and the quality of correlations between the random function and the variables from seismic data.
This paper presents an original approach for building complex 3D prior probability fields of geological facies. It constitutes a very challenging way of integrating two major advances in geosciences in recent years: geostatistics and sequence stratigraphy.
From facies descriptions on cores and logs, palaeobathymetry curves of deposits are constructed for each well. Logs of the accommodation potential (increment of space available for sediment accumulation) are then produced from those curves and deposit thicknesses in the wells.
A Principal Components Analysis of data in all wells makes it possible to separate the signal into two components: a common factor which represents the tectono-eustatic activity at field scale (easily extrapolated), and residuals which correspond to local variations in subsidence. 3D grids of accommodation potential and palaeobathymetry can then be modeled, with respect to the time intervals within each layer.
Geological inversion is therefore possible and leads to the proposal of a complex 3D prior probability field for facies modeling, with different organizations in both the transgressive and the prograding parts of the sequence.
When constrained by such trends, stochastic modeling (object based or SIS) can render very realistic images of reservoir heterogeneity.
This method was applied successfully in carbonate and mixed (silici-clastic and carbonate) platform reservoirs, in which properties are highly variable and non stationary.
Geostatistical Quantification of Geological Information for a Fluvial-type North Sea Reservoir
Authors: Caers Jef K. , Srinivasan S. , Journel Andre G. 
Published: December 2007

Abstract
Accurate prediction of petroleum reservoir performance requires reliable models of the often complex reservoir heterogeneity. Geostatistical simulation techniques generate multiple realizations of the reservoir model, all equally likely to be drawn. Traditional to geostatistics, geological continuity is represented through the variogram. The variogram is limited in describing complex geological structures as it measures correlation between rock properties at two locations only: it is a two- point statistic. Reservoir analogs such as outcrops can serve as training images depicting the interpreted geological structure. Due to scarcity of well data, the variogram models are often borrowed from such training sets. However, the same training images could be utilized to extract more complex information in the form of multiple point statistics measuring the joint dependency between multiple locations.
This paper compares a traditional variogram-based geostatistical model versus a novel geostatistical method utilizing multiple point statistics borrowed from training images. The comparison is made on the basis of flow performance for a typical North Sea reservoir. To obtain such comparison a "true" reference reservoir is generated using object-based simulation that depicts the complex intertwining of fluvial channels. Next, a different but similar reservoir is generated, termed the "training reservoir". The latter is used to extract the necessary structural information, be it variograms or multiple-point statistics, to build multiple geostatistical models of the "true" reservoir conditioned to sparse well data. A water flood flow scenario with inverted 5-spot pattern is simulated using ECLIPSE on the true reference and the various geostatistical models. Water breakthrough characteristics and water saturation distributions are used for comparison.
Application of Intelligent Completion Technology to Optimize the Reservoir Management of a Deepwater Gulf of Mexico Field – A Reservoir Simulation Case Study
Authors: Rester Stephen , Thomas Jacob , Hilten Madeleine Peijs-van , Vidrine William L. 
Published: December 2007

Abstract
The objective of the 'intelligent completion' concept is to provide the operator with a completion method that will allow reconfiguring of well architecture as well as acquisition of real-time data whenever needed — without rig intervention! As with all unique operational strategies that significantly differ from traditional concepts, there are always questions as to whether the new techniques can really achieve the sought- after economic and operational benefits as well as how candidate wells can be chosen.
This paper will discuss a study that was performed to demonstrate 1) that intelligent completion technology could be successful in optimizing the management of a field through controlled commingling of production and 2) that it could increase flexibility of making operational changes.
The project considered a deepwater Gulf-of-Mexico field that consists of several stacked sandstone reservoirs that are separated by shales. A multi-well development plan using dual completions and rig recompletions had been established for this field prior to the commencement of this study. A review was made of the wells in the development plan and the geology of the field to select appropriate candidates for possible replacement of the traditional completions with intelligent completions. Two wells were chosen for the study. Reservoir simulation was used to estimate the production profiles for several cases with conventional completions and for two cases with intelligent completions. In the existing development plan, both of the wells were to be completed in one reservoir initially and recompleted in a different reservoir later.
For each well, the application of intelligent completion technology accelerated production and eliminated the need for a rig recompletion. The simulation results showed that the single well economics would be improved for both wells being studied. Although some of this improvement was offset by well interference effects, overall, the field economics were enhanced. The data obtained from the study will illustrate that there are economic advantages to applying intelligent completion technology in the appropriate well scenarios. Also, methods for estimating the performance of intelligent completions will be evaluated.
A Thermodynamic Modelling Method for Organic Solid Precipitation
Authors: Mei Haiyan , Kong Xiangyan , Zhang Maolin , Sun Lei , Li Shilun , Sun Liangtian 
Published: December 2007

Abstract
A gas and oil system contains a certain amount of heavy organic substances, such as wax, resin and asphaltene which precipitate as a solid phase, causing serious problems to production for oil and gas fields, when thermodynamic conditions are changed.
In this paper, a thermodynamic model of the gas-liquid- solid three-phase equilibrium for an oil and gas hydrocarbon system is presented, based on the regular solution theory, an equation of state and the phase equilibrium principle of fluid thermodynamics. A flash calculation model for the gas, liquid and solid three phases is developed, being combined with a material conservative equation. An equation of state is used to describe both gas and liquid phases, and a regular solution theory is only used to account for the non-ideality of the solid mixture, which can reflect the effects of temperature, pressure and composition of system on solid precipitation. The influence of the heat capacity difference between the liquid and the solid on the solid precipitation is taken into consideration. Some adjustable parameters and a tuning function are introduced in this model because of uncertainty of heavy component properties. It is shown that the model has a good convergency and stability, and the calculated values by this model are in good agreement with the experimental data.