bluuebunny/crossref_metadata_2025_split huggingface dataset:
Seismic Mapping of Reservoirs at the Golfo San Jorge Basin
Authors: Borderas Marcelo , Ledesma Mario , Courtade Sergio 
Published: December 2007

Abstract
Reservoir maps are amongst the most important data necessary for oil exploration and development. Reservoir mapping through seismic data at San Jorge Basin has always been difficult due to the low thickness of the individual sandstones.
The techniques of seismic reservoir mapping based on the integration of the top and base reflection amplitudes and the seismic isopach map allowed us to map successfully reservoirs in the order of system tracts in those cases where sand and shale thickness were beyond the tuning thickness.
The technique involves a detailed well tying through synthetic seismograms at the control wells. This allows to obtain the phase of the seismic data and to identify the seismic response of the different lithologies. Based on this tying the top and base of the reservoir interval are carefully picked. From these picks the reflection amplitudes at the top and base of the interval and their isopach map are extracted, quality controlled for tuning and calibrated. The final reservoir thickness is obtained from the integration of the data and it is quality controlled against the existing wells.
This methodology allowed us to map reservoirs at the Salamanca and Yacimiento El Trébol Fm. at the North Flank of San Jorge Basin and at Mina El Carmen Fm. at the north and west flanks of the basin.
As a summary, this technique allows us to map reservoirs at the system tract level at the northern flank of Golfo San Jorge Basin in those cases where there is poor well control and results are not interfered by tuning. Although there are more sophisticated techniques (seismic inversion, geostatistical inversion), this one let us do a fast mapping of the reservoirs. On the other hand, the tying and picking involved in this technique can be applied as an input to the most sophisticated techniques.
Successful Liner Application Using Foamed Cementing Technology for Low-Pressure, Naturally Fractured Formations
Authors: Degni Carlos D. , Fuller George A. , Chumpitaz Dino 
Published: December 2007

Abstract
This case history includes the design, testing, job execution, and post-job results of a successful foamed spacer/cement application. During this application, a liner was cemented across a productive formation in which a significant amount of low-density mud was lost during the drilling phase.
During a deep-well drilling campaign in Argentina, a naturally fractured formation located between 3828 m and 4290 m experienced severe lost circulation. Once this section was drilled, a single-stage cement slurry needed to be placed without major cement slurry losses to the formation. The section then needed to be successfully sealed from the shoe to the top of the liner. Additional consideration was given to minimizing fluid-loss damage to a potentially productive zone that consisted of low-pressure microfractures and large fractures.
One of the most difficult challenges in a cementing operation is getting successful cementing results across low-pressure formations that have lost-circulation tendencies. Although alternative methods involving stage tools and top squeezes can be considered, liner applications tend to complicate the operational phase because of liner hangers, tool outside-diameter (OD) geometries, plugs, and pressure-activation requirements. An additional challenge was to effectively remove the residual mud filter cake from the annulus of a 15° uncentralized casing in a deviated wellbore.
After all potential challenges to this liner application were addressed, a foamed cement/spacer system was determined to be the best solution for meeting all objectives and completing the liner application. This lightweight cementing system possesses many benefits, including (1) superior mud displacement, (2) high strength, (3) low density that can be adjusted onsite, (4) ductility for preventing stress cracking during the casing pressure test/drilling phase, and (5) the capability to prevent gas migration from the major fracture network of the productive formation.
Production Restarting on Asphaltene-Plugged Oil Wells in a Lake Maracaibo Reservoir
Authors: García M. C. , Chiaravallo N. , Sulbarán A. , El Chiriti K. , Chirinos A. 
Published: December 2007

AbstractAsphaltene plugging is one of the most frequent causes of production depletion in medium and light crude oil reservoirs, specially when the pressure declines due to its exploitation, and asphaltene solubility reaches a minimum. Other physico-chemical phenomena, like intrinsic unstability of the produced crude oil, incompatibility between "commingled" produced oils, drilling fluids and produced oil, or between streams entering flow stations, as well as inadequate stimulation procedures, can be responsible for asphaltene deposition during crude oil production and transportation, going from the reservoir to surface facilities. Prevention methods oriented to asphaltene deposition control include the injection of chemical additives. These products have the particularity of disperse or inhibit asphaltene aggregation, avoiding the formation of precipitates that eventually deposit on metal or mineral surfaces, causing a severe flow reduction, and even formation or tube plugging. The main purpose of this work is to show the application of a systematic technique for chemical treatment evaluation, oriented towards the production restarting of asphaltene plugged oil wells in a Lake Maracaibo reservoir. Dead oils and deposits from neighbor oil wells of the same reservoir were characterized, along with the evaluation of some commercial additives, in terms of their performance as asphaltene deposition inhibitors, under atmospheric conditions. The results allowed selecting the best product to be evaluated under reservoir conditions. Its addition to live oil samples, at reservoir pressure and temperature, showed a clear reduction of the asphaltene precipitation pressure onsets. A complete chemical treatment, including the selected product, was used for production restarting of the plugged oil wells. Field operation procedures used in these cases are described. Also, production history data of the actual oil wells, comparing their productivity before and after the treatment, are shown in order to demonstrate the efficiency of the methodology.
Drilling in High-Temperature Areas in Brazil: A Wellbore Stability Approach
Authors: Falcao Jose L. 
Published: December 2007

Abstract
In this work the stress concentration around unlined holes in areas classified as High Temperature (HT) is determined. The thermal stress generated due to the difference between the drilling fluid and the undisturbed formation temperature is evaluated through an axysimmetric Finite Element Model (FEM) employing the Galerkin’s method and four nodes quadrilateral elements, using a transient non-linear thermoelastic solution. In addition, the thermal effect is compared with the mechanical effect, induced by the drilling process (excavation and internal pressure), to assess its significance. Moreover, it is shown, through two field cases in HT areas in Brazil, that failure to consider the thermal effect can lead to misjudgments in the evaluation of the potential wellbore stability.
A New Approach to Identifying Operational Conditions in Multivariable Dynamic Processes Using Multidimensional Projection Techniques
Authors: Ranson A. , Hernández K. Y. , Matheus J. E. , Vivas A. A. 
Published: December 2007

Abstract
Industrial processes may have a large number of measured variables. Combining these variables is possible to identify different operational regions and detect anomalies or deviations within the process. However, it is hard to visualize operational conditions and identify problems on line. The difficulties arise because the field operators must observe and analyze dozens of variables concurrently in order to identify the operational state of the process. This is not a new problem and previous attempts to find a solution have limitations to overcome. One traditional approach was to assign alarms to each variable to alert operators about potential problems. However, far from solving the problem, this technique aggravated it, mainly because there were too many alarms and a number of them turned to be false. This prompted the operators to ignore the control system, which made things worse. A novel multivariable-process visualization technique is being proposed to help in the tasks of supervision, observation of operational states, and detection of problems in multivariable processes. The technique combines steady-state-detection filters, statistical filters, pattern matching, and spatial transformations for the gathered data. A spatial transformation is the key element for data processing, and consists of a space-reduction algorithm based on keeping a set of attributes unchanged between the original space and the projected space. This paper describes a general methodology to monitor multivariable industrial processes. The methodology was applied to a control test case as well as a real time debutanizer column process.
A Multidiscipline Approach for the Development of a Waterflood in the Chihuido de la Salina Field
Authors: Corbett C. , Blekhman V. , Coca B. , Diaz D. , Selva G. , Ayala M. , Pina L. 
Published: December 2007

Abstract
The Chihuido de la Salina field is situated in the folded thrust belt of the Neuquen basin of Argentina. The field is composed of several structural blocks, which have gas caps of different relative sizes. The most important blocks have oil legs in steeply dipping flanks. The structure presents particular problems for both geologic modeling and numerical simulation for the generation of a waterflood development plan. This paper presents the techniques used to incorporate pertinent information from many different disciplines and create a numerical model that enables reasonable predictions for a variety of development scenarios.
In this study data was available from the domains of Petrophysics, Geophysics, Geology and Reservoir Engineering. Each of these data provide valuable information but at radically different scales. To gain the maximum benefit from all the data a multidisciplinary interpretation was implemented to cross-validate the data and to extrapolate from one scale to another important reservoir behaviors. The controlling factors for the fluid behavior, apart from the fluids themselves, are the variations in structure, reservoir property (porosity, permeability, thickness) and stratigraphic sequence variations.
For the analysis of the structure a 3D seismic dataset provided a basis for the geophysical interpretation of a time-indexed horizon, which was then converted to depth. Velocity information was initially derived from well control and a geostatistical analysis of stacking velocity, but this proved to be insufficient in the steeply dipping flank areas critical to the oil production. Log data, mud returns and well deviation surveys, provided exceptionally accurate dip and fault data, which combined with the geologic interpretation, constituted a sound basis for a local flexure in the depth structure.
A sequential gaussian simulation conditioned to well data provided the basis for porosity distributions. Core and Well Test pressure transient data were analyzed to infer permeability and these results were then used to carefully calibrate permeability derived from well log data. The log data provided a measure of the vertical heterogeneity and a sequential gaussian co-simulation to the porosity distribution provided the final geostatistical realization of the property model.
Experimental Study of Morichal Heavy Oil Recovery Using Combined Steam and Propane Injection
Authors: Goite J. G. , Mamora D. D. , Ferguson M. A. 
Published: December 2007

Abstract
Laboratory experiments have been conducted to investigate the use of propane as a steam additive to enhance production of 13.5°API oil from Morichal field, Venezuela. The main component of the apparatus is an injection cell into which is tamped a sand mix consisting of sand, water, and oil. Thermocouples placed in the cell enable tracking of the steam front. The cell pressure is set at 50 psig, while superheated steam at 160°C is injected at 5 ml/min cold-water equivalent at the top of the cell. Produced liquid is collected from the bottom of the cell, and after emulsion-breaking treatment, oil and water volumes are measured.
Experimental runs have been conducted in which the propane:steam mass ratio is varied from 0:100 (steam only) to 5:100. A run using 5:100 nitrogen:steam mass ratio has also been made to evaluate the contribution of convective heat to oil production. The main findings of this research (derived from four runs with consistent operating conditions) are as follows. First, the propane:steam mass ratio of 5:100 accelerates the start and peak of oil production by 20 % and 13 % pore volume steam injected (cold-water equivalent), compared to steam injection alone. In the field, this could translate into significant gain in discounted revenue and reduction in steam injection costs. Second, oil recoveries appear to be similar in all cases, 63 % – 70 % OOIP. Third, the start of production is practically the same for 0:100 and 1:100 propane:steam ratio and for 5:100 nitrogen:steam ratio, indicating probably a minimum propane:steam ratio requirement. Fourth, oil production acceleration in the 5:100 propane:steam case is probably caused by ‘dry distillation’. Last, convective heat transfer at any of these low (5:100) ratios appears to be of secondary importance. Research continues to better understand the mechanism and thereafter model the production of oil under steam-propane injection.
Field Development Extensions of Orocual Field and Prediction of Expected Performance in a Fractured Reservoir
Authors: Agostino Guerini , Lugo Claudia , Vargas Marielis , Rincones José , Márquez Pascual , Porjesz Robert , Dorta Gustavo , Smith Richard , Melendez Luis , Delgado Rory 
Published: December 2007

Abstract
The Orocual Field is made up of four structurally compartmentalized fault blocks. The upper two, San Juan 3 (SJ3) and San Juan 6 (SJ6) are more developed. The lower block structures, San Juan 7 (SJ7) and San Juan 9 (SJ9), are more than 1500 feet deeper and are separated by a major thrust fault. These reservoirs primarily consist of light condensate. Recent development suggests that significant potential exists in the SJ6 and SJ7 areas. The difficulty in defining the hydrocarbon column associated with each block, because of limited development, shows significant sensitivity in calculating oil reserves. The San Juan formation is a naturally fractured sandstone reservoir, and has historically produced low sustained rates of less than 1000 BOPD. New techniques in the area have been studied to increase sustained rates to at least 3000 BOPD.
This project was designed to develop a method to analyze the probable results of a development program. A reservoir simulation model was constructed as part of an integrated study focused on geostatistics modeling of tight matrix and fracture systems to predict production by extending the proven area of the field. The producing areas have limited data, and previous studies did not consider the fractured nature of the reservoir. The application of geostatistical methods for reservoir characterization, and the use of simulation to assess the static model heterogeneity were identified objectives. The complex structure and fluid columns add to the uncertainty. Various sensitivities were run by applying different constraints to the permeability model, variance in fluid definitions, and well design.
The reservoir simulation model shows sensitivity to matrix characterization and less to fracture characterization. This sensitivity is related to well productivity as a function of matrix permeability. The matrix is so tight that a multiple increase of permeability has little effect on well productivity. The permeability appears to be predominately from fractures. Fracture density or fracture permeability shows less effect to change well productivity than matrix permeability. Over 100 simulations were run to predict well and reservoir behavior. Results allow realistic assessment of risk in both reserves and production and to rank alternatives.
A Two-Phase Model Coupling Reservoir and Horizontal Well Flow Dynamics
Authors: Vicente Ronaldo , Sarica Cem , Ertekin Turgay 
Published: December 2007

Abstract
A fully implicit, three-dimensional simulator with local hybrid grid refinement around the wellbore is developed to solve reservoir and horizontal well flow equations simultaneously for liquid-gas flow systems. The model implements the conservation of mass equations in the reservoir and conservation of mass and momentum in the wellbore for isothermal conditions. Establishing the continuity of pressure and preserving mass balance at the sandface satisfy the coupling requirements between the two computational domains. The hydrodynamic model for the wellbore is based on the homogeneous flow assumption.
The model is used to simulate the transient pressure and flow rate behaviors of reservoir and horizontal wellbore. The traditional approach of decoupling of wellbore flow from reservoir flow does not capture the horizontal well pressure and flow rate transients at early times since the interaction between the reservoir and wellbore is inherently neglected. Simulation runs with the proposed model reveal the realistic characteristics of horizontal wellbore storage and unloading. By conducting a series of parametric study, effects of permeability, formation thickness, well length, fluid compressibility, reservoir anisotropy, and selective completion strategies on the coupled reservoir and horizontal well flow dynamics are investigated.
Hydraulic Fracturing As A Sand Control Method: Experimental Work On The VBR-24 Well, Vibora Field, Bolivia
Authors: Casares Miguel Angel , Talavera Juan Felipe 
Published: December 2007

Abstract
This paper describes an experimental work in Hydraulic Fracturing performed on a gas reservoir that has a very thick friable sandstone, the object of which is to control the production of formation sand and optimize field exploitation.
The Yantata formation in the Vibora Field in Bolivia is formed of a very fine-grained sandstone that is poorly consolidated, with a thickness of 80 meters net average. It produces gas and condensate and has serious sand production problems.
In order to avoid the sand influx, the wells were produced with very small choke orifices for years, restricting the field's hydrocarbon production.
Lately gravel packing has been used with good results, but the great thickness of the productive reservoir leads to the need for more than one packing per well. This necessitates the use of complex and costly dual facilities that at the same time impede production in the same well of other two reservoirs present in the field.
The hydraulic fracturing was carried out on the VBR-24 well and was designed to open about 40 meters in height from the top of the reservoir, where only 7 meters were perforated and vertical communication was ensured for at least the top half of the total thickness of the reservoir, eliminating possible sedimentary barriers.
In order to neutralize sand migration a proppant covered with curable resin was used. The resin coating increases the strength of the sand grain to resist crushing and, as it cures in the formation, the coating bonds the individual grains together impeding flow-back and without reducing greatly the permeability.
The results obtained were successful because the well produces more gas and condensate than the majority of the wells that produce with gravel packing, it does not add sand and it has a simple facility that eases entry into the well for future interventions.
Methodology for Optimum Exploitation Plan Integrating Technical and Economical Elements: Field Case
Authors: Pellacani M. Bracho , Romero J. E. , Gonzalez M. 
Published: December 2007

Abstract
Reservoir studies traditionally developed by PDVSA have contemplated the execution of three phases: I, data base construction; II, reservoir characterization and III, numerical simulation culminating in a technically viable development plan. The approval process in PDVSA for the implementation of reservoir studies results includes two additional phases: IV, design of an optimun exploitation plan using financial evaluation tools and risk analysis and V, formulation of the operating plan of the selected exploitation scenario. This paper presents the methodology for integrating phases IV and V with the results obtained in the conventional phases of a reservoir study.
Utilizing Old Logs to Enhance Static Reservoir Models Prior to Simulation In Mature Oil Fields, Acema Area, Eastern Venezuela
Authors: Naranjo E. , Bellorin O. , Cabrera J. , Boulter R. , Suter A. , Vargas W. , Morland A. 
Published: December 2007

Abstract
Innovative static geological modeling techniques provided input to construct dynamic reservoir simulation models of mature oil reservoirs as a key step in facilitating optimal field development planning.
Accurate modeling of these stratigraphic reservoirs, deposited in nearshore marine to coastal plain environments, required innovative modeling because only 71 wells had suitable logs for petrophysical analysis. The other 146 wells had only an SP or GR and resistivity logs.
A modeling technique was designed to utilize logs from all 217 wells. The primary properties extracted from all the wells was a gross sand thickness map and depositional environment maps for each reservoir to be modeled. These calculated sand thicknesses were then interactively contoured to produce gross sand maps using the depositional environment maps to shape the gross sand distribution. These two types of maps were then used in deterministic modeling software to shape and control the mapping of some reservoir properties.
After petrophysical reservoir properties were calculated in the wells with petrophysics, it was found that net reservoir sand, net pay thickness and average reservoir porosity often had high correlation coefficients to gross sand thickness. In deeper layers, there was a secondary correlation between porosity and depth. These correlations were used to guide the distribution of reservoir properties.
Dynamic engineering data were then integrated into reservoir property maps to refine the positions of the lateral flow unit boundaries and in some cases the downdip water contacts.
This innovative modeling technique demonstrates how accurate reservoir models can be constructed in fields with limited log data.
The resulting geological model was used as the basis for the construction of numerical reservoir simulation models. These simulation models are vital tools for predicting expected reservoir performance and for optimizing field development planning to maximize the recovery of remaining hydrocarbons.