bluuebunny/crossref_metadata_2025 huggingface dataset:
Improvement of Sweep Efficiency by Microbial EOR Process in Fuyu Oilfield, China
Authors: Nagase K. , Zhang S. T. , Asami H. , Yazawa N. , Fujiwara K. , Enomoto H. , Hong C. X. , Liang C. X.
Published: December 2007

This field test for Microbial EOR (MEOR) has been carried out in Fuyu oilfield, China since 1996. Waterflooding by a patterned flood has been applied for over 20 years and various measures to decrease high water cut has been discussed for long time in Fuyu oilfield.

The objectives of this MEOR project are to increase oil production from a waterflooded reservoir and to evaluate ability of microorganisms screened in our study. In this field test a microorganism named CJF-002 was applied to reservoir. CJF-002 has an ability of producing insoluble polymer metabolically on the condition that fed on nutrient. This microbial process has focused on plugging high permeable zones by produced insoluble polymer to reduce water channeling.

Actually, microbial approach using CJF-002 has been performed by injecting into (1) production wells as huff-n-puff test (single cycle) for confirming polymer production potential and (2) injection wells as microbial treatment for water injection profile modification. In huff-n-puff test, CJF-002 and molasses were injected into 6 production wells. Among them, 4 wells indicated oil production increase and water cut decrease. Based on these possible results of huff-n-puff test, microbial treatment was conducted at injection wells for injection profile modification. In the treatment, cell count of CJF-002 and concentration of insoluble polymer in the sample taken at the manifold and some production wells were measured to investigate the metabolic activity of CJF-002 by colony forming unit (CFU) method and HPLC, respectively. Moreover, logging such as RST and WFL and tracer test were conducted before and after microbial treatment to evaluate the effect of microbial treatment. As a result, microbial propagation and metabolic activity was confirmed, however, the effect of injection profile modification has not been confirmed yet. This paper presents results and status of MEOR field test conducted in Fuyu oilfield, China.
Using Genetic Algorithms to Improve Investment Decision Making
Authors: Sarich M. D.
Published: December 2007

Investment decision-makers in the oil and gas industry are faced with an extremely complex process when attempting to decide on the optimum mix of projects to pursue. Almost all firms are faced with constraints such as capital budgets, volume commitments and/or dependent and mutually exclusive projects. Likewise, attempts to include the objectives of planning, finance and engineering can make it almost impossible to find the optimum mix of projects using traditional selection methods.

Indicators from discounted cash flow analysis such as net present value, rate of return and profit investment ratios have traditionally been used to rank projects, however these rankings will not necessarily produce the best result. In addition, unless the number of potential projects under consideration is very small it can be unfeasible to evaluate all of the possible permutations. Therefore, how does one know if the best value-creating portfolio of projects has been chosen?

A recently developed technique for solving this type of problem is the use of Genetic Algorithms. Borrowing from the biological field of evolution, algorithms have been developed that can be applied to find a combination of projects that approach the true optimum, taking in to account numerous business constraints, within an acceptable time frame.

This paper describes the theory behind genetic algorithms and their application to investment decision making in the oil and gas industry. A worked example for a hypothetical company is then used to demonstrate the potential impact of using the technique.
Reservoir Engineer and Artificial Intelligence Techniques for Data Analysis
Authors: Tapias O. , Soto C. P. , Sandoval J. , Pérez H. H. , Bejarano A.
Published: December 2007

Different knowledge areas on the petroleum industry require to solve problems related with data transformation processes needed to generate information and knowledge. This paper describes data analysis steps using Artificial Intelligent techniques which include the problem exploration, space analysis, surveying data source, data preparation and building the appropriate data mining model. Predictive and inferential models are illustrated by applications implemented using Unsupervised Artificial Neural Networks and a Fuzzy Rule Diagnosis System. (1) The first application is able to identify well zones potentially producing hydrocarbons in Colombian PETROLEA field. This reservoir is mainly a fractured and calcareous formation. The knowledge predictive model uses Fuzzy Learning Vector Quantization (FLVQ) built from historical production tests data and spontaneous potential, short and long resistivity well logs used for training, testing and validating the model. The final Bravais & Pearson correlation factor obtained is 0.95. (2) Finally a Fuzzy Rule Diagnosis System is applied to enhanced oil recovery screening comparing technical information from reservoir, well and oil properties. The model uses heuristic and lab results for knowledge base implementation adapted to Colombian oil fields.
Experiences with Gravel Packing in the South Tapti Gas Field - An Unconsolidated, High Permeability Sandstone Reservoir
Authors: Das Subhas C. , Garred Michael A. , Suhail Kak
Published: December 2007

The South Tapti gas field, located in the Arabian Sea off the western coast of India, has been on production for the last three years. Drill Stem Tests (DST) conducted in five zones in the first appraisal well showed high sand production in all the tests at drawdowns as low as 20 psi. Due to the unconsolidated nature of the reservoir sand, it was decided to gravel pack all future wells.

Initially, the High Rate Water Pack (HRWP) technique was used on 13 completions including some stack and selective completions. Due to a change in the drilling fluid to an oil based mud (OBM) system and the higher damage associated with the it, it was later decided to switch the gravel packing technique to ‘Frac and Pack’. This involved creation of a small frac to bypass the near wellbore damage using a gel-based fluid, followed by gravel placement using the HRWP. The Frac & Pack technique was tried on 10 completions.

Extensive production and pressure data collected on the above completions show that the ‘Frac & Pack’ technique has led to a decrease in the mechanical skin by almost 70 %. More importantly, it has also been responsible for decreasing the Rate Dependent Skin Coefficient, D, by 50 %, which has a greater impact on the well productivity since these wells are produced at average rates of 25 MMSCFD.

This paper describes the gravel packing techniques used in the South Tapti gas field, their evolution and the results achieved.
Thermal Stress of Carbonate Rocks: An Experimental Approach
Authors: Zekri Abdulrazag Y. , Chaalal Omar
Published: December 2007

The most commonly used methods of describing fluid flow in oil reservoirs use constant rock properties. However, these methods are not applicable to reservoirs that undergo changes in the rock properties due to variation in pore pressure. A common characteristic of fractured reservoirs is sensitivity of permeability and porosity to effective stress. The in-situ stress, in itself, can be of mechanical or thermal origin. The thermal stress can be significant in thermal enhanced oil recovery schemes, injection of cold fluid in hot formation during water flooding or wastewater disposal, or during hydraulic fracturing.

An extensive literature review reveals that the research in this area has focused only on thermal recovery of heavy oil. Little has been done to investigate the onset and propagation of fractures under thermal stress or even mechanical stress. Consequently, this paper is devoted to investigate fracture development and propagation in carbonate formation under thermal and mechanical stress. A series of experiments were ingeniously designed to study the effect of thermal stress on fractured carbonate formation. Laboratory experiments were conducted to determine stress-strain relationship and their time dependence, fracturing and propagation of fractures. A computer image analyzer was used to observe the fracture/fissures distribution for various cases of thermal stress on carbonate rocks. The role of thermal and mechanical stress in determining orientation and propagation of fractures was also studied.
Process for Recovery of Extremely Shallow Heavy Oil
Authors: Osterloh W. Terry , Jones Jeff
Published: December 2007

In this paper, we propose a new process for recovery of heavy oil from sands at depths of 100 ft or less and report its feasibility as determined by reservoir simulation. The process, called blanket heating, recovers oil by the traditional mechanisms of viscosity reduction and gravity drainage, but avoids the problem of handling large volumes of injected fluids and reduces the risk of surface emissions that would occur with typical steam EOR methods.

Simulation results indicate that excellent, thermally efficient oil recovery is possible. Process sensitivity to many critical parameters was determined.
Application of Flexible Gridding Technique to Simulate Gravity Drainage in ESOZ
Authors: Ahmed Mahbub , Singh S. P.
Published: December 2007

Eastern Shallow Oil Zone (ESOZ) of the Elk Hills field is a thick sandstone reservoir whose structure is complicated by the presence of numerous faults. ESOZ is being exploited by both vertical and horizontal wells. This paper describes the adaptive flexible simulation grid employed and the results obtained in modeling the South Flank of Eastern SOZ. Representing a highly faulted reservoir through ordinary Cartesian grids poses challenges to the reservoir simulation engineers in that the fluid flow across these geological boundaries are not modeled properly. Also, horizontal and inclined wellbores present near wellbore phenomena that are difficult to be represented by classical Cartesian Grid system. The use of Perpendicular Bisection (PEBI) grid in the study has greatly enhanced the quality of reservoir simulation. The recovery from south flank having a dip of about 25 degrees is dominated by gravity drainage. The reservoir pressure is depleted to 100 – 200 psi in the oil productive zone. The objective of the model study was to understand the degree of sealing across the faults, sand units and estimate future recovery under various reservoir management options. Eighty years of production history was simulated to properly establish current pressure and saturations in the model. Next, several forty-year prediction runs were performed to investigate the effect of gas injection, gravity drainage, infill drilling and water injection. The model results show that a combination of gas injection and infill drilling would further increase future oil recovery from the south flank.
Predicting Foamy Oil Recovery
Authors: Mastmann Manuel , Moustakis Michael L. , Bennion D. Brant
Published: December 2007

With a current recovery of only 5 percent, Albania's largest oilfield Patos-Marinza, first commercially produced in 1939, still yields a potential of more than 100 MMbbl reserves of 10 – 12°API oil from a depth of 1600 m. A consortium consisting of the Albanian Albpetrol, the German Preussag Energie, the British Premier Oil, and the IFC, the private sector arm of the World Bank, are making plans to improve oil recovery.

Testing wells producing 1-2 m3/d yielded rate improvements with Progressive Cavity Pumps up to 30 m3/d with sandcuts around 10 to 35 %. PVT analysis of the oil with a relatively high solution-GOR of 35 m3/m3 shows a strong tendency to foam (gas in microbubbles without forming a continuous gas phase) below the bubble point, near the initial reservoir pressure. Core tests with different depletion rates resulted in primary oil recoveries of greater than 30 %.

For predicting project recovery and eonomics a black oil simulation model was built with ECLIPSE on the basis of the lab results. The sand production was inferred through channels laid out in a star-like manner with a single cross connection. Constructing type wells a sensible forecast including sand was attained.

The paper discusses all measurements and results in the context of present theories of foamy oil and Cold Heavy Oil Production (CHOP).
A Semi-Analytical Pressure Transient Model for Wells in Heterogeneous Linear Reservoirs
Authors: Sagawa Atsushi , Corbett Patrick W. M. , Davies David R.
Published: December 2007

A new semi-analytical model for vertical or horizontal wells in heterogeneous elongated linear reservoirs is presented. In fluvial environments, such reservoirs can be formed due to the effect of low sinuosity river channels.

Transient pressure response or fractional flow rate from well segments can be calculated using the model. To obtain the solution, semi-permeable wall model and strip-wellbore model are used. A wellbore may penetrate several different permeability zones and skin factor can be different along the wellbore. It is shown that early-time linear flow behavior, which can be often seen in acidized carbonate reservoirs, can be approximated by the strip-wellbore model.

Type-curves for the heterogeneous elongated linear reservoirs, which may be used directly in well test analysis, can be generated using the model developed in this study. If the results of production logging are available, they are useful for the analysis since the transition of fractional flow rate from each well segment can be calculated. Such analyses become important to determine the size and rock properties of each heterogeneous zone, which is critical for future production forecast.

The validity of the model is confirmed by comparison with the results of numerical simulation. This study provides a new tool for studying and analyzing the pressure behavior of wells completed in fluvial environments as well as acidized carbonate reservoirs.
Development and Testing of Two-Phase Relative Permeability Predictors Using Artificial Neural Networks
Authors: Silpngarmlers N. , Guler B. , Ertekin T. , Grader A. S.
Published: December 2007

Artificial neural networks (ANNs) provide a powerful toolbox to perform nonlinear, multi-dimensional interpolations. In this paper, we include a new methodology to identify some of the vague nonlinear relationships that exist between rock and fluid properties and relative permeability characteristics. More specifically, we report liquid/liquid and liquid/gas two-phase relative permeability predictors that we have developed using back-propagation networks. In this class of ANNs, information is passed from input layer to output layer, and calculated errors are propagated back to adjust the connection weights in a sequential manner to improve the predictive capabilities of the models. In the development stage, some of the relative permeability data from literature are used during the training stage while some other sets are preserved to test the prediction capabilities of the models. Various rock and fluid properties such as end-point saturations, porosity, permeability, viscosity and interfacial tension and some functional links (mathematical groups coupling various rock and fluid properties) constitute the input parameters of the models. These rock and fluid parameters together with the functional links highlight the dependency of relative permeability characteristics on such properties and functional groups. The models developed for oil/water and oil/gas systems are different in terms of their respective topologies, functional links, and the weight updating schemes. The models are found to successfully predict the field and experimental relative permeability data.
Permeability Calculations from Clustering Electrofacies Technique for the Petrophysical Evaluation in La Peña and Tundy Oil Fields
Authors: Antelo Roberto , Aguirre Omar
Published: December 2007

A relatively new technique has been applied for the purpose of providing more accurate Permeability information and identify rocks types with good fluid flow characteristics from wireline logs data.

The study for which this technique was applied included wells drilled over the last 30 years up to present. When you have a wide range of logging tools and differences in logs scales or presentations it becomes really difficult to identify the existing facies on a depositional cycle just by following the shape of the log curves. Even when you count with a consistent or homogeneous log set of curves, the task of identifying the different facies is often difficult.

The technique used applies the clustering K-Means2 algorithm based on wireline logs characteristics to identify the different Electrofacies. The Electrofacies found were very useful to determine rock types with identifiable fluid flow characteristics. Porosity/Permeabilty relationships were then assigned to the various Electrofacies and used to calculate permeabilties during the log analysis.

The method was applied for 79 wells from La Peña Field and for the 9 wells from the Tundy field and proved to be very successful in dealing with a wide heterogeneous range of wireline log types when working on a multiwell field petrophysical analysis. The application of this technique is very simple if we look at the existing pattern recognition software designed to identify facies that include the complicated stochastic algorithms which usually requires the operation of skilled users in order to obtain impressive results.

This paper presents a description of the clustering K-Means2 algorithm used for the Electrofacies calculations and also shows the permeabilities results obtained in the petrophysical analysis for each of the Facies. Finally some examples of the petrophysical evaluation and the calculated Electrofacies will also be visualized graphically and discussed here.
Secondary Migration of Oil: Analytical Model
Authors: Bedrikovetsky P. , de Deus J. , Altoé J. E.
Published: December 2007

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

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

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

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

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

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

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

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

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

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

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

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

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

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.
Reservoir Geophysics: Seismic Pattern Recognition Applied to Ultra-Deepwater Oilfield in Campos Basin, Offshore Brazil
Authors: Johann Paulo , de Castro Dayse D. , Barroso Alberto S.
Published: December 2007

Usually, seismic data is used in a qualitative approach to detect changes in the waveform and to pick acoustic continuity of a peak and/or a through as a structural mapping tool. The seismic interpretation is a qualitative process for building a geological model. Today, many works try to use the seismic information in a quantitative approach. Seismic interpretation in a quantitative approach is a key process in the integration of geoscience data at scales from basin-wide studies, reservoir focused and field-development process. Quantitative modeling could be deterministic and/or probabilistic. We use, in many steps of a seismic processing sequence, examples of quantitative deterministic modeling like seismic migration, some seismic inversion methodology, etc. Probabilistic modeling can be gathered in two groups: multivariate statistics and geostatistics approaches. Close to probabilistic modeling, we have also the neural network method. In this paper, we focus on the application of neural network modeling for seismic pattern recognition (seismic facies analysis) applied an ultra-deepwater turbidite oilfield reservoir in Campos Basin, offshore Brazil.
Lateral Delineation of Sandstone Bodies Guided by Seismic and Petrophysical Data Using Geocellular Model: Cañadon Seco Formation, San Jorge Basin, Argentina
Authors: Guerberoff David , Zucchi Hector , Marcos Victoria , Robles Gervasio
Published: December 2007

The studied area is characterized by sandstone-shale complexes vertically arranged in a column of approximately 200 m. Conventional well correlations provide high uncertainty in sandstone prediction because of the high variability and small lateral extension of the bodies. We rely on geo-statistical techniques of interpolation of the petrophysical variables supported by seismic derived attributes. Seismic-petrophysical matrixes and cross plots were constructed to high correlation coefficients. Having the linear correspondence between the variables, an adjusted function allow us to find the unknown values (petrophysical) from the seismic data using geo-statistical methods such as Krigging and Co-Krigging. The grids of petrophysical values feed a geocellular model where they are volumetrically interpolated. This static model can be used through "up scaling" in a future dynamic model for reservoir simulation.
Horizontal Underbalanced Drilling in Northeast Brazil: A Field Case History
Authors: Cunha J. C. , Rosa Fábio Severo , Santos Hélio
Published: December 2007

This paper describes aspects related to planning and execution of four horizontal wells drilled underbalanced in the Estreito Field. This field is located in Brazil's Northeast Region (fig. 1) and has its production zones depleted. It was discovered in 1982 and today it has more than 700 wells. Estreito field has its producing reservoir very shallow and the formation is very unconsolidated, these poses especial challenge to achieve and maintain underbalanced condition at all times during the drilling operation, requiring especial care not only during the planning, but also for the execution of the well operations. In order to achieve the required bottomhole pressure (ECD=6.9 ppg) nitrogen was injected into the water base drilling fluid, through the standpipe. Since the wells were horizontal, it was required the use of electromagnetic MWD/GR once the regular MWD would not work properly on a gasified fluid. In these wells it was successfully tested a compact vertical gas-liquid separator with an automated control system and data acquisition system developed by Petrobras. A skimmer was used for the solids-drilling fluid-oil separation.
What Have We Been Doing Wrong in Wellbore Stability?
Authors: Santos Helio , Perez Roberto
Published: December 2007

Identification of the correct cause of wellbore instability is the key to quickly solve the problem. This paper presents some results of tests conducted to check the behavior of preserved shale samples when immersed in different solutions, trying to identify the importance and relevance of the osmosis as well as the effect of other components in the mud, such as the emulsifier. Results showed that not only the salinity of the mud is important. Also, in some situations, rock swelling did not follow what states the osmosis theory, leading to a conclusion that other phenomena are relevant and with a similar order of importance.

The paper also discusses the mechanism of micro-cracking with subsequent fluid penetration, and the use of a truly non-invasive fluid to avoid the instability. Field cases are reported, demonstrating the effectiveness of using such approach. The paper also presents the problems ofcurrent rig site monitoring tests that can induce wrong interpretation of the real cause of the problems.
Shell Separation Technology from the Wellhead to the User
Authors: Bergerman S. D. , Polderman H. G. , Bravo J. L.
Published: December 2007

Advantaged separations technology has proven to be key in the success of the hydrocarbon production processes of Shell over the years. R&D as well as benchmarking efforts over the years have yielded a varied slate of separation process technology that has found wide application in the field. The Shell separation technologies cover the range of phase separation, distillation hardware, and process design and are pervasive in the hydrocarbon supply chain from production to manufacturing.
Diadema Project - Underground Gas Storage in a Depleted Field, in Patagonia, Argentina
Authors: Rodríguez Juan José , Santistevan Pedro
Published: December 2007

Underground gas storage is a common activity in countries with major transport and distribution gas pipeline infrastructures, which allows to efficiently resolve demand seasonality problems.

So far, Argentina, with major winter demand peaks and its fields located thousands of kilometers away from consumption centers, has not developed UGS facilities, despite the maturity the industry has reached in the country, which has one of the highest rates of natural gas participation in the power matrix worldwide (47%).

The first ever underground gas storage project in Argentina is being carried out in the Diadema field, located near the city of Comodoro Rivadavia - Province of Chubut, with injection and withdrawal operations starting as of 2001. (Fig. 1)

The goal of this project is to contribute to modulate oil and gas production in the fields of the region, transporting and storing part of the overproduced gas in the Austral and San Jorge Basins during summertime, to have the necessary gas available during the winter peak season, allowing producers to comply with their contract obligations.

With this goal in mind, several studies have been carried out, including reservoir modeling and simulation studies, gas injection and interference tests, the workover of gas input wells and monitoring wells, as well as the construction and revamping of the necessary surface facilities for storage operations.

Considering the size and geographic location, the Diadema project will be a pilot operation in the region, which will serve as a model for future undertakings.