bluuebunny/crossref_metadata_2025_split huggingface dataset:
Secondary Migration of Oil: Analytical Model
Authors: Bedrikovetsky P. , de Deus J. , Altoé J. E. 
Published: December 2007

Abstract
An analytical model for segregated 2-phase flow for secondary migration of hydrocarbons from mother rock to reservoir is developed.
The model accounts for different distribution of oil over the carrier bed cross section during the primary drainage, when oil invades the water filled formation (during oil generation by the mother rock), and during primary imbibition, when the water moving down displaces oil ‘bottom-up'. It results in a hyperbolic first order partial differential equation with hysteresis. It is shown that the hysteresis phenomenon affects highly the amount and distribution of residual oil in the carrier bed after reservoir formation.
The model was validated by prediction of hydrocarbon reservoirs in Basin P (Brazil).
Oil Mixture Viscosity Behavior: Use in Pipeline Design
Authors: Degiorgis G. L. , Maturano S. , Garay M. , Galliano G. R. , Fornes A. 
Published: December 2007

Abstract
A properly understanding of how oil mixtures behaves as they flows in a pipeline is a key factor for piping design.
Facilities engineers from oil companies currently use commercial pipeline simulators in order to perform pressure and temperature gradients predictions.
Nearly all the simulators apply the general mixing rule when they need to calculate the viscosity of a certain oil mixture.
As viscosity depends both on molecular characteristics and molecular interaction, and oil is a complex mixture of components, it is not surprising that this rule gives poor results. Besides, non-Newtonian behavior makes things more complex.
This paper discusses experimental results of mixing at lab several different oils and measuring their viscosity. Each oil had its own composition and rheological behavior. Some mixtures were prepared in order to reproduce real situations.
Once the mixtures viscosities were obtained they were introduced as input data in a commercial pipeline network and nodal analysis software.
Then, pressure and temperature gradients were calculated Using the experimental mixture viscosityUsing the general mixing rule viscosity estimated by the software
Results showed, in some cases, dramatic differences between the two alternatives. Higher deviations were obtained where the mixtures were composed of crudes of different properties.
In order to improve the accuracy other mixing rules were tried and some of them fit better.
A proper understanding of crude oil properties seems to be essential for successfully applying complex simulators in pipeline design.
Use of a Heat Conveyor Increases Capacity of Artificial-Lift System in Viscous Oil Wells
Authors: Eloff A. , Cavieres G. Gómez , Milathianakis J. , Gordillo E. , Gonzalez E. 
Published: December 2007

Abstract
There are high permeability reservoirs and high viscosity oils at the Manantiales Behr Oilfield located in northern San Jorge Basin. In order to be able to profitably produce the wells drilled in these areas it is necessary to optimize the methods and elements used, as well as to permanently search for new alternatives. It is within the frame of this continuous search that a new downhole system that provides heat distributed along the production tubing was experimented. The generated heat maintains the temperature and viscosity of the reservoir produced oil within an acceptable values range for the artificial lift systems used. This enables the increase of the production rate and minimizes operative costs due to well interventions.
Environmental Impact of Internal Combustion Vehicles: A Proposal for a Comparative Study Betwen Natural Gas and Liquid Fuels
Authors: Gómez D. R. , Reich S. L. , Gil S. , Loza J. C. , Maubro M. A. 
Published: December 2007

Abstract
We present the outline of an expert system for assessing the environmental impact of different fuels used in all kind of internal combustion vehicles in Argentina. The objective of this system is to have an adequate and continuously upgrading tool able to simulate different scenarios of the composition of the transport fleet in a given city and, for each case, evaluate the environmental impacts as well as the externalities. We include a reference study of traffic influence on air quality for a receptor site located in a heavy traffic street near the downtown area of Buenos Aires. The guiding principles and general details of the proposal are given in this work.
Designing Underbalanced and Lightweight Drilling Operations; Recent Technology Developments and Field Applications
Authors: Rommetveit Rolv , Lage Antonio Carlos V. M. 
Published: December 2007

Abstract
Underbalanced and lightweight drilling is very promising method to solve numerous drilling problems in depleted reservoirs, mature fields as well as deep-water regions. Also, maintaining underbalance during the whole drilling operation will prevent or reduce formation impairment in various formation types. In order to properly design an underbalanced operation, good control of the downhole pressures is necessary. A technology programme to develop a dynamic underbalanced drilling simulator, for proper design of operations has been undertaken. This work has included laboratory experiments, modelling achievements as well as full scale testing. Comparison of full scale data as well as field data with simulations show that the simulator predict very well the steady state downhole pressure conditions for most gas – liquid rate combinations within the realistic operational range. Also, transient pressures during rapid operational changes can be predicted well.
In parallel, an innovative separator system and methodology for utilising UBD techniques in offshore operations have been developed.
These technologies have been utilised in an offshore environment, for the purpose of developing lightweight drilling offshore.
This paper will present the various technology elements developed (dynamic simulator; separator system and methodology for lightweight drilling) and present verification tests and field applications of these in an offshore environment.
Toward Zero Damage: New Fluid Points the Way
Authors: Di Lullo Gino , bte Ahmad Atikah , Rae Phil , Anaya Luis , Meli Ricardo Ariel 
Published: December 2007

Abstract
It is well known that increasing the ionic strength of aqueous solutions containing certain categories of anionic surfactant can produce interesting behaviors. The molecules of some surfactants cluster together forming spherical micelles. However, a select few surfactants, with particular molecular structure, undergo a remarkable transition from spherical micelles to larger, anisometric aggregates. The size, flexibility and extent of interaction of these aggregates all have an influence on the rheological properties of such solutions, producing very substantial viscosities at low shear rates.
Conversely, when these surfactant solutions encounter other chemical species, particularly relatively non-polar materials, like alcohols, glycols and hydrocarbons, this affects the shape and structure of the micelles. As a result, the phase behavior is altered and the solution undergoes a dramatic reduction in viscosity.
Proper selection of a surfactant allows its application in several oil field treatments such as reservoir gravel packing, frac-packing, fracturing, brine thickening, non-damaging temporary plugs and also for reservoir flooding and water shut-off.
The main advantage of these solutions, compared to conventional polymer systems, is the potential for reduced formation and proppant pack damage. However, there are many other advantages. These fluids exhibit unexpectedly low high-shear viscosities resulting in low friction pressures, even in small tubular. In addition, due to the very low viscosity of the broken fluid, faster load recovery of injected fluids is possible. A final benefit offered by these systems is operational simplicity at the well site, since there is no need to "pre-gel" tanks ahead of the treatment.
This paper describes the chemistry involved to develop these viscous solutions and their applications in different treatments in the field.
Rock Typing: A Key Approach for Petrophysical Characterization and Definition of Flow Units, Santa Barbara Field, Eastern Venezuela Basin
Authors: Porras J. C. , Campos O. 
Published: December 2007

Abstract
The Santa Barbara Field is located in the North Monagas Area, Eastern Venezuela Basin. Reservoirs in the area are characterized by high initial temperature and pressure, and high initial production rates. The drive mechanism is solution gas drive and fluid expansion, with reservoir pressure declining rapidly. The hydrocarbon column varies from a gas-condensate cap at the top of the structure to heavy oil at the bottom. A detailed petrophysical model was necessary to optimize the secondary recovery processes implemented in the field.
The petrophysical characterization incorporated the analysis of the complex variations in pore and pore throat geometry that control initial and residual fluid distribution and fluid flow through the reservoirs. Conventional porosity and permeability, mercury injection capillary pressure, relative permeability, and mineralogical data were used to characterize the reservoir pore systems into rock types having similar flow and storage capacity. Water Saturation, all of which is considered immobile, was found to be dependent on rock type, with pore throat being the dominant control on the flow characteristics of the reservoirs.
Mercury injection capillary pressure data provided useful information about effective pore throat radii, which were semi-quantitatively related to several reservoir responses, such as permeability, porosity, irreducible water saturation, and a capillary pressure profile or pore throat type curve. Plots of pore throat obtained from empirical equations versus pore throat estimated from capillary pressure tests showed that the dominant interconnected pore system that controls flow in the reservoirs is best represented by the pore throat on a capillary pressure curve corresponding to 45% mercury saturation.
Rock types were considered for the definition of injection intervals, and were also used to construct stratigraphic flow profiles, which were validated with production logs. Grouping similar rock types was found to be an excellent method for defining simulation layers. Rock type areal distribution maps were constructed to help delineate the best reservoir areas.
The characterization of a reservoir into rock types in order to determine flow units effectively integrates geological, petrophysical and production data into descriptions of zones with similar flow characteristics, and is fundamental for the development of secondary recovery processes.
Rock Typing: Key Approach for Maximizing Use of Old Well Log Data in Mature Fields, Santa Rosa Field, Case Study
Authors: Boada E. , Barbato R. , Porras J. C. , Quaglia A. 
Published: December 2007

Abstract
The Santa Rosa field is located in the greater Anaco area in the Eastern Venezuela Basin. A total of 280 wells have been drilled, 65 with modern porosity logs. This situation makes the reservoir very difficult to be evaluated using only well log classical techniques. In the studied reservoir have been completed 74 wells, the production started in 1950, and a gas injection project was implemented in 1955. With the purpose of validating reserves and optimizing exploitation plans a petrophysical model based on rock type characterization was developed using existing cores, logs and production data. This model was extrapolated to the rest of the wells.
Rock type characterization was based on mercury injection capillary pressure data, which allowed the determination of pore throat profiles for each rock type and the dominant interconnected pore system, which corresponds to a mercury saturation of 35% in a capillary pressure curve. An empirical relationship was used to related conventional porosity and permeability with pore throat, and was used to classify rock types.
The upscaling procedure from core to logs was accomplished through a relation between gamma ray and neutron logs with core porosity and permeability in a key well. These relations were found to be dependent on rock type, and were used to extrapolate core characterization to those wells with only gamma ray or neutron logs. Porosity obtained from wells with neutron/density logs was compared to porosity obtained from the gamma ray - neutron -core porosity relationship, with very good results.
Maps of rock type distribution were used to identify reservoir zones with better quality rock. These maps along with facies maps from the sedimentological study helped delineate the reservoir limits, in order to validate and identify prospective areas for future drilling.
The characterization of a reservoir into rock type integrating geological, petrophysical and production data is fundamental for the development of exploitation plans.
AVO Analysis in Cerro Piedra Field, Golfo de San Jorge Basin, Argentina
Authors: Pianelli L. , Scazziota F. , Galofre M. , Barreto G. Lara 
Published: December 2007

Abstract
The Cerro Piedra field, west of Las Heras (Province of Santa Cruz), is one of the fields located on the western flank of the San Jorge basin.
The occurrence of both amplitude anomalies, as seen on the seismic section, and gas layers (penetrated by several wells) which partially account for such anomalies led us to carry out this study. Its main objective is to implement a methodology aimed at identifying gas zones, which can be extrapolated into adjoining fields.
Well data, detail geologic correlations, velocity laws, VSPs (YPF.SC.CP.X-4 and YPF.SC.CP.e-21 wells), and 2D seismic sections are available to achieve the above objective.
The study has focused on a gas layer of Tertiary age which occurs at a depth of about 500m below ground level and is approximately 30 m thick. The main interest of this layer concerns its fluid content and the fact that it is within the seismic resolvable limit.
3D Seismic Surveys Improve the Cost/Benefit Ratio
Authors: Egusquiza M. I. 
Published: December 2007

Abstract
3D seismic surveys improve the cost / benefit ratio by reducing dry-hole risk and by providing better well placement. This is achieved through specials seismic studies.
In this case study, geologic data and seismic attributes are linked by geostatistic methods. The target is to find and track sand body orientations which make up the reservoir. A Schlumberger GeoQuest, software package (comprehending seismic, petrophysics and geostatistics) was used to reach the results.
Geostatistics was used first to know about available data, find relationship between seismic and borehole data, and then use the lessons learned to grid borehole data taking seismic data as a guide. The objective is to create sand thickness maps by intervals taking into account the anisotropy of the medium.
The study was develop in a part of the Cañadón de La Escondida reservoir located in the Golfo San Jorge Sedimentary Basin, Argentina. In this field, the producing intervals lie between 2200 m to 2800 m with isolated sand bodies which average thicknesses from 5 to 10 m. The traps have both a structural and stratigraphic component. The depths of the interest zones and the low final recovery, make it hard to recover the investment. Therefore, it is critical that the prediction of special studies are as precise as possible, in order to drill profitable wells.
An Approach to Naturally Fractured Reservoir Characterization: Case Study, San Juan Formation, Orocual Field, Venezuela
Authors: Dorta G. , Boujana M. , Zerpa L. , Ramonez M. , Velasquez C. , Castillo E. 
Published: December 2007

Abstract
For the first time, in Venezuela, a detailed, complete study of naturally fractured reservoirs using the recent technological advances was performed. Since the first drilled well within the very tight (5 mD) cretaceous sandstone (San Juan Formation) diagenetically highly cemented by quartz overgrowth, the existence of natural fractures was suspected due to high production rates (3000 bopd) after hydraulic fracturing an interest in fractures characterization became important for the field. Furthermore, these assumptions were growing with the analysis of pressure transient tests of several DST and Build-up surveys, which have shown double-porosity behaviour. During the drilling it was frequently observed strong lost of circulation at several depths within the San Juan Formation.
Orocual Field, within El Furrial Trend, located in North Monagas area, East of Venezuela, is structurally a Fold Propagation Fault resulting in anticlines associated with thrust faults. San Juan Formation, a complex barrier island deposits, bearing condensated fluids (41° API) is the most important reservoir within Orocual Field.
Cores and Well Logs provided the basis to strongly confirm the presence of a fracture network within the reservoir. With the use of recent technological advances (core scanning and imaging, side-by-side display) which permits a detailed core-log calibration and integration, a NNW-SSE orientation of the fractures observed and measured in the cores was possible, the findings are consistent with the regional tectonical stress. Integrated analysis with breakouts borehole image processing, 3D seismic structural interpretation, in-situ stress measurements and second derivatives maps yield us to establish the first maps of fractures orientation and density.
Parameters such as aperture, spacing, density, length and angles have been measured to define patterns and tendencies that it will feed the simulated dynamic fractures model.
A better understanding of the historical production behaviour has been reached and a simulated, geostatistical fractures modelling is under development to establish correlative trends matching between production and fractures network orientation, density and dynamical properties of the fractured system.
Calibrating Log-Derived Permeability Data to PTA for Geostatistical Integration into a Fluid-Flow Simulation Model
Authors: Blekhman V. , Diaz D. , Carrica P. , Corbett C. , Coca B. , Gomez U. 
Published: December 2007

Abstract
One of the classic problems in the development of a reservoir numerical simulation model is the question of scale. Data that are acquired from many different sources give us a view of the reservoir under different constraints. In this paper, we present a technique that integrates data from the core scale to that acquired through logs to well-test pressure transient analysis (PTA) and, finally, to the production history information. A field example from the Neuquen Basin demonstrates this procedure.
PTA offers a reasonable estimate of the permeability within the drainage radius of the well. Unfortunately, these measurements usually are not made in every well. Log data typically is acquired in the field from most wells. Using recovered core data and permeability analysis from cores, a probabilistic petrophysical model, honoring that core data, is constructed. The petrophysical model is applied throughout the field and used in constructing a geocellular model. The model can be investigated in positions equivalent to the volumes investigated by the PTA, and the petrophysically-derived permeability can be iteratively modified to match the permeability derived from the PTA. The geocellular model is upscaled for dynamic fluid-flow simulation. Finally, the production history is compared with the simulation results. The process becomes an iterative loop to achieve the best match of all the available data. This process facilitates the final history match to gas, oil and water production.
Precuyano: A Nonconventional Reservoir in the Neuquen Basin, Mendoza, Argentina
Authors: Fernández M. L. , Brissón I. E. , Loza J. , Arias L. Rodríguez , Dzelalija F. 
Published: December 2007

Abstract
The aim of this paper is to emphasize the oil discovery in the pyroclastic deposits of the Precuyano Cycle, in the Valle del Río Grande exploitation block. Since the Precuyano deposits were set in production, these levels have provided considerable wealth of oil, if we compare them to the daily average production of the block. This discovery has brought about a new impulse to the exploration of this kind of reservoirs, which have proved a strong potential in improving the oil production of the zone.
This report includes an update of the investigation performed in this unit; it is main purpose of this job was to characterize the reservoir and their oil potential from a series of petrographic, petrophysical and diagenetic analysis. The analysis of the dominant structural styles integrated with the reservoir conditions was essential in order to reduce risk in deep exploration programs and to optimize the field development.
Well logs were used as interpretation tools for this nonclassic reservoir; borehole images helped to assess the dominant stress fields; and correlation graphics (cross plots) were used to determine the mineralogy and porosity.
Estimation of Reservoir Net Thickness Using Seismic Facies and Well Data in Middle Miocene Incised Valley Deposits of the Oficina FM. Oritupano Area, Eastern Venezuela
Authors: Azálgara C. , Floricich M. 
Published: December 2007

Abstract
The Oritupano block is located on the southern part of the Maturin Sub-basin, in the Eastern Foredeep Basin of Venezuela. In this area, the Oficina Fm., with ages ranging from early to middle Miocene, consists of 2100 feet of sandstones interbedded with shales deposited in a ramp setting. The objective of this study is to characterize the B Sands of the Oficina Fm., integrating well logs and 3D seismic data. Seismic and well data indicate that B Sands, with average thickness in the study area of 110 feet, are Lowstand and Transgressive System Tracks (LST-TST) deposits bounded by a Sequence Boundary at the base (SB B) and a Maximum Flooding Surface at the top (MFS B). The seismic expression of these surfaces is, respectively, a negative and a positive polarity reflection interface (SEG polarity standard). Horizon slices created from the MFS B show persistent NE trending geological features through a time interval of 20 milliseconds below the MFS B. Synthetic seismograms indicate that this time interval includes most of the B Sands incised valley deposits. This time window was used to construct a seven-classes seismic facies map. Seismic facies analysis assesses the variation in seismic wavelet shape over an interval of interest. Cross correlation between seismic facies and the petrophysical properties of 40 wells indicates a close relationship between seismic facies and net thickness for the B Sands interval. An integrated net thickness map of the studied interval was obtained through the following steps: (1) Well grouping through net thickness vs. seismic facies crossplot. (2) Computation of the net thickness average per seismic facies class. (3) Generation of a net thickness map assigning the net thickness average value to each seismic facies class. (4) Flexing of the map obtained in the previous step to the well net thickness values. This integrated net thickness map allows: the prediction of net thickness in non-drilled areas, the estimation of reserves, and a reliable input for simulation studies.