bluuebunny/crossref_metadata_2025 huggingface dataset:
Experiences in the Use of ESP's in Orinoco Belt Cerro Negro Area, Venezuela
Authors: Ramos Marcelo A. , Rojas Carlos R.
Published: December 2007

Traditionally, in the Cerro Negro area up until 1995, conventional rod pumping units and progressive cavity pumps were used in vertical and inclined wells with production rates ranging between 200 and 600 b/d.

With the incorporation of the horizontal drilling technologies in unconsolidated sands for the construction of wells with high productivity indexes (4-6 b/d/psi), the evaluation of electrical submersibles pumps (ESP) begun as an alternative to handle high production volumes of 8 degrees API bitumen characterized by its viscosity of 5500 cp at a reservoir temperature of 130°F.

To aid production, a dual well completion design was used, parallel to the production tubing a second tubing with a smaller diameter was installed to allow diluent (32°API) injection at the bottom of the wells, diluting the bitumen from 12.5 to 13.5° API, an decreasing its viscosity to a range of 500–800 cp. Additionally, buy lowering the viscosity gas separation was aided before the intake of the pump.

At the beginning of the project, ESP's with nominal capacities of 4000 b/d of flow were installed in re-entry wells, diluent injection was done using ½" coiled tubing attached to the production tubing parallel the power cable, reaching production rates in the order of 800 to 1000 b/d of bitumen. Subsequently, in new horizontal wells, ESP's with capacities of 8000 and 6000 b/d of flow were installed, and two different diluent injection string designs were used.

The first design used was two 1/2″ coiled tubing strings assembled with the power cable, with this system diluent was injected at the pump level; the second design was regular 1,5-1,9″ cs-hydrill tubing strapped to the production string, allowing diluent injection below the pump, at the top of first slots in the horizontal liner

This second system was selected as standard together with ESP with a nominal capacity of 6000 b/d. Bitumen production rates ranging from 1500 to 2000 b/d of bitumen are obtained by injecting 400 to 600 b/d of diluent, decreasing friction losses and obtaining an average of 30% of pump efficiency. Additionally, the use of the system has increased the run life of the pumps, actually 33 months.

To improve the efficiency of the ESP pumps new devices are being tested, an inducer was installed in substitution to the down hole gas separator. Simulations indicate that this device, placed at the intake of the pump, will permit gas handling through the pump, decreasing the fluid column weight.
Orinoco Belt, Cerro Negro Area: Development of Downhole Diluent Injection Completions
Authors: Alexander Rojas R.
Published: December 2007

Traditionally, in Orinoco Belt Cerro Negro area, Venezuela, beam, progressive cavity and electrical submersible pumps have been used for bitumen extraction.

In order to facilitate bitumen transportation down hole to surface, diluent is injected to decrease formation viscosities which are in the order of 5000 Cps at reservoir conditions (135 F, 3500 ft depht and 1200 psia).

Diluent is injected through the annular space, by gravity in beam and progressitive cavity pumps. This method, in some cases, does not guarantee proper dilution at the entrance of the pump because of the gas accumulation at the annular section, causing, in some cases, lifting problems, such as high torque, high loads in the rod strings, damages in the rods, operational problems in surface lifting units and pumps working at maximum discharge pressures limits.

In order to guarantee proper operation in the electrical submersible pumps bitumen should be diluted before entering to the pump.

In 1995, some tests began with new completion designs, in order to guarantee an homogeneous mixture at the bottom. The result has been a different completion for each method, using additional accessories at the entrance and at the discharge of the pumps, to improve transport, pumping efficiency, higher production and an improvement of the system running life.

The design consists on a injection port located, either at the pump entrance or at the pump discharge a continuous 3000 ft 0.5" or 1.9" diameter tubing, and a perforated injection 1.9" diameter tubing attached to injection port allowing the diluent get to the producing zone in order to improve dilution..
Emerging Technologies in Subsurface Monitoring of Petroleum Reservoirs
Authors: Islam M. R.
Published: December 2007

Most oil fields do not produce more than 45% of the oil-in-place, even after enhanced oil recovery schemes have been applied. Most of this unproduced oil is missing because most displacement techniques by-pass significant portion of the original reserve. Finding this missing oil can lead to significant economic windfalls because the infrastructure for additional oil recovery is already in place and the cost of production is likely to be minimal. In this paper, all existing monitoring techniques, including 4D seismic and downhole seismic sensors, are reviewed. This is followed by a comprehensive review of emerging technologies in subsurface monitoring. These techniques include multi-well seismic, electrical resistivity tomography, electromagnetic and ultrasonic imaging, acoustic and fibre-optic imaging, as well as laser/infrared or MRI/NMR visualization near the wellbore region.

A detailed analysis indicates that for an accurate reservoir engineering analysis, geostatistical models should have information of 1m scale. This is the only scale that would satisfy the representative elemental volume (REV) requirement of an enhanced oil recovery (EOR) system. This scale length is orders of magnitude higher than that of core samples and at least an order of magnitude lower than the conventional seismic data. This data gap constitutes the weakest link between geophysical information and reservoir engineering. Any attempt to reconstitute the reservoir without information regarding petrophysical properties and fluid saturations in the 1m level, one risks falling into the trap of multiple solutions – a typical problem of history matching through reservoir simulation. To obtain a resolution of 1m scale, one must investigate the possibility of using 50-2000 Hz seismic frequency range. While this seismic range cannot be used with vertical seismic profiles (VSP) because of the travelling distance constraints, multiwell imaging can be used with multi-component receivers. This system, in combination with borehole seismic sources, can provide one with the desired resolution. The same system can be used in combination with resistivity tomography, a method that has recently given satisfactory results for tracking ground-water contamination. The images can be further refined with acoustic and fibre-optic imaging techniques. These techniques can provide satisfactory details to track viscous fingering, wormholes, and other time-dependent properties of an active reservoir. Finally, infrared/laser or MRI/NMR imaging of a wellbore is still in its nascent state of development, but holds great promises for the future applications of real-time monitoring and eventual dynamic reservoir management.
Early Environmental Warning System for Underground River Crossings
Authors: Pisano Guillermo , Bouzas Carlos , Villa Horacio
Published: December 2007

This is an example of the application of a combination of the latest technologies to assure the early detection of leaks in underground river crossings and environmentally sensitive zones of gas and oil fields operated by Perez Companc.

One of the most important environmental impact risks within our oil and gas production operations is the potential possibility of spilling hydrocarbons to our rivers. Tens of cities, that take drinking water for the human consumption or that use the resource as a means of recreation and thousands of hectares irrigated for the maintenance of the agricultural and cattle-raising activity, gives significance to these risks.

To reduce these risks in the 260 mts. long underground crossing of the Neuquén River, located in the Neuquén province, Argentina, an annular casing system was devised. This space is pressurized with nitrogen to a level over that of the pipeline. Any abnormal condition is detected through the supervision of both the casing and pipeline pressures with a very simple control logic implemented in a remote transmission unit (RTU)

In case of a leak, or defect in any system, the RTU is responsible for closing pipeline valves and sending remote and local alarms to the field's SCADA system. The RTU is connected to the Supervision, Control and Data Adquisition (SCADA) System through a digital Spread Spectrum radio link.

The simplicity of the control logic and the pressure transmitters and communication system reliability assures an interesting cost-benefit relationship.
Extensive Evaluation of Aerated Accumulation Technique for Soil Treatment
Authors: Ercoli E. , Gálvez J. , Calleja C. , Calvo V. , Cantero J. , Videla S. , Medaura M. C. , DiPaola M.
Published: December 2007

A pilot study of hydrocarbon biodegradation in soil using the aerated accumulation technique (AA), performed in the oil field Loma La Lata of Repsol-YPF SA in the province of Neuquén (Ercoli and others, IAPG, 2000) yielded satisfactory results. We considered the possibility of applying this biological technique on the treatment of big amounts of contaminated soil. The experimentation showed the possibility of reaching cleaning goals in comparative shorter periods of time, of about three months, starting from soils moderately contaminated with light hydrocarbons. Some important advantages in comparison with other biological techniques such as land-farming or biorestoration were additionally observed. The moisture of the soil was maintained during the treatment with no need of extra addition of water - cost to be considered in superficial treatments- and produced an important spontaneous increment of the temperature of the soil. These two characteristics of the process are particularly attractive for arid soils and cold regions, since these two factors, scarce humidity and low temperature, delay the global kinetic of biodegradation.

On the base of the pilot experiment results, the application of the technique in larger scale on diverse kind of contaminated soils in oil field of Neuquén province was decided. Volumes of 20000 m3 of lightly contaminated soil, 8000 m3 of moderated contaminated soil and 22000 m3 of highly contaminated soil, were treated. In all of the cases, an efficient reduction of the contaminants up to predetermined values was observed. The evaluation of these parameters let us conclude that an important number of cases of contaminated soils with hydrocarbons can be resolved in an efficient and economic form using this technique.
Lateral and Vertical Discrimination of Thin-Bed Fluvial Reservoirs:Geostatistical Inversion of a 3D Seismic Data Set
Authors: Marcos Victoria , Merletti German , Cuenca Alvaro Grijalba , Verdin Carlos Torres
Published: December 2007

The San Jorge Basin is one of the most prolific hydrocarbon bearing zones in Argentina.The Cañadon Seco Formation is characterized by sandstones with thickness usually bellow the tuning lenght, under these conditions high uncertainty exists in sandstone prediction when seismic amplitudes are analyzed, due to interference and tuning effects. This paper presents an estimation procedure that overcomes these limitations based on the extrapolation of the well data further away from its location by Geostatistical Inversion of 3D seismic data. Although vertical sampling of the seismic data is much less dense than the one from logging, its higher lateral resolution is used to complement the high vertical resolution of the well data. Unlike conventional trace based inversion in which the source is the seismic data in Geostatistical Inversion the data source is the well, and the estimated acoustic impedance values satisfy the seismic data, in this way driving resolution to an intermediate range between the well and seismic data. With this procedure stochastic simulations of the petrophysical variables are generated, (density and lithology) that not only honour the hard data of the wells but also the seismic data, and minimize the residual error between the Synthetic model and the real 3D-Seismic trace. Each simulation (SGS-Simulated Annealing and SIS) is itself a possible solution to the problem and it is called a realization, wich is then integrated into an average to optimize the certainty of the predictions. The Acoustic Impedance, density and lithology models derived from GI have a resolution of 1ms. This allowed discriminations of lateral variations in the petrophysics of the reservoir (density porosity) and the delineation of sand packets of up to 6 meters thick. The Geostatistical Inversion turned out to be a very powerful tool for the static reservoir modelling wich can function itself as an input to the dynamic model (reservoir simulation), guide the development of the block and assists to the EOR.
Seismic Mapping of Reservoirs at the Golfo San Jorge Basin
Authors: Borderas Marcelo , Ledesma Mario , Courtade Sergio
Published: December 2007

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

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

Asphaltene 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

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

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

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

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

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

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

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

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

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.
Probabilistic Model to Develop Multilayer Gas and Oil Prospects
Authors: Faya Luis C.
Published: December 2007

It is not that uncommon when putting together an exploratory program to find that there are several prospects within a block, and/or several reservoirs within an individual prospect. Given that we could successfully develop each prospect, the total value of the property will be equal to the sum of the individual prospects, i.e. we can add the Net Present Value (NPV) distributions taking into account the probability of success of each prospect to obtain an estimation of the block's value. This simple process will be complicated when one or more of the prospects have more than one potential layer.

We can solve this problem by introducing simplifications, such as adding all the layers and developing them as one unit. But what if they are at different depths, have different productivity index, gravity or impurities? We can also build a decision tree that takes into consideration the different future scenarios. This is usually tedious, time consuming and we could introduce additional bias when having to assign probabilities to the different branches.

This paper shows a simple methodology to build a probabilistic production forecast, capital and operation expenditures for a prospect with several layers, in order to make an economic evaluation of an exploration opportunity.
Variation of the Mechanical Properties for Cementing Slurries with Different Compositions
Authors: Altuna Gustavo , Centurion Sergio , Perez Ipina Juan E.
Published: December 2007

Without any doubt, the primary cementing of a gas / oil well is the most critical stage in its life. The cement will make the isolation between zones and will avoid any kind of communication, it will also protect the casing from external fluids or pressures, and it will bring the necessary structural support.

When one design is made, a lot of disciplines (chemistry, geology, physics, mechanics, electric, etc) will participate to define the final design.

Anyhow, in the completion / production phases of the well, the cement is subjected to higher loads or higher stresses that were designed for the goals above mentioned. For example, when a well is perforated, it is subjected to high dynamic loads and high variations of temperature. Another example is when a hydraulic fracture is performed or when it is converted into a multi-lateral well.

A lot of effort was made to improve the techniques in the completion process but not enough to study the way to give the cement column better mechanical properties, and let it improve its strength throughout the well's life. On the other hand, the criterion to analyze the stability of the cement is through the compression strength that changes with time and composition.

The industry accepts that the cement has a very limited capacity to support tensile load. In addition, there is little knowledge about the behavior of a crack under a tensile load and how it behaves as a function of time.

In this paper, the behavior of two cementing slurries with different compositions through the use of Linear Elastic Fracture Mechanics (LEFM) [1], the fracture toughness and their variation with time were analyzed. The variation in the mechanical properties was focused in two slurries with different compositions. The difference was the addition of a styrene-buta-diene latex in the cement slurry.

The fracture toughness variation through setting time was studied; having been observed a maximum toughness value between 7 and 21 days.

All the slurries were mixed under API- Spec10 [2] requirement and all the tests were performed taking into account E 1820-96 ASTM standard [3].
Interventionless Production Packer Setting Technique Reduces Completion Costs
Authors: Patterson Daniel L. , Taggart Ian D. , Breivik Harald W. , Scott Gordon , Simonds Randy , Falconer Rod
Published: December 2007

Developing marginal petroleum fields or extending the life of mature fields becomes significantly more attractive when technology is available that can enhance cost efficiency and reduce operational and environmental risks. To support the above needs, a major oilfield equipment supplier has introduced an interventionless technique for setting production packers downhole that provides an alternative to conventional setting procedures. When applied to the proper scenarios, the costs relating to setting the packer can be substantially reduced. The system can be used for completions where the capability to set and retrieve a plug is deemed virtually impossible or when the use of wireline or coiled tubing tractors would be very costly and risky. Basically, the system reduces the intervention risks by eliminating the need for intervention. This paper will describe the system, its testing, and the structured approach that was applied throughout system development to enable the concept to materialize from its initial concept to a finished product.

Using this technology, a packer can be set without using such traditional techniques as setting and retrieving plugs. In addition, no complicated tools or hazardous materials are required. The concept uses the hydrostatic pressure of the well to provide the energy supply to set the packer. The application of a predetermined surface pressure initiates the setting sequence and does not require electronics or special surface equipment.

Two offshore North Sea case histories that will provide data that verifies the cost advantages provided to the operator when the hydrostatic-set packer system is used will be discussed.

In fact, one of the wells in which this technology was used is the longest extended-reach horizontal subsea completion in the world to date.
Seismostratigraphic Model of the Tundy Field Carboniferous Reservoirs, Chaco Basin, Bolivia
Authors: Kusiak M. E. , Cardona R. , Rivero J. L.
Published: December 2007

The Carboniferous Glacio-Eustatic Reservoirs of the Tundy Field related to the San Telmo Formation, represent fluvial and shallow marine facies. San Telmo Formation was deposited in the Upper Carboniferous transgressive-regressive cycles associated with common climatic changes in these glacially influenced intracratonic basins. These Carboniferous reservoirs are mostly associated with stratigraphic-structural trapping and the Devonian shale's as a source rock. The sequence is divisible into three units in order to determine an accurate siesmostratigraphic model. Two marine units and one fluvial unit are recognized from 3D seismic and wells drilled in the study area. The Lower Marine Unit is the lowest shoreline deposit and consists predominantly of shaly sediments. They are upward-coarsening successions that represent parasequences deposited during a high stand of relative sea level that were incised by streams and were partly eroded during a lowering of relative sea level. The Upper La Peña Fluvial Unit is the aggradational valley fill that was accumulated on the subsequent rise of relative sea level. This stacking fluvial channels unit is aquiferous with a considerable thickness in Tundy Field and productive in the La Peña neighbour Field. The Upper Marine Unit, accumulated when the sea transgressed across the area from southwest to northeast, has two shoreline distinguished sand bodies; one of them is the main reservoir in the Tundy Field and thins toward its landward pinch-out. Conclusions on the 3D seismic interpretation have an excellent coherence between the geological units that are supported with interference and pressure analysis and studies obtained in the field.
DBU+ A Geoscience Integrated Tool
Authors: Albano J. R. , Dogliani J. , Pandolfo L. E. , Quintana J. C.
Published: December 2007

With the aim to get a reliable, integral, simple and efficient tool for information access requested in geosciences project, we have developed a computer integral system for access, validation and preservation of data and documents.

The kernel system is a relational data base with a set of validation process to guarantee the consistency and quality of information. This Kernel is interfaced with a document management system to visualize scanned document.

The front-end for data access is an interactive graphical interface with functionality to open specific applications, well logs and seismic lines export to integrate project, to retrieve production and workover dates, to display geological cross sections, to visualize scanned documents, etc.

The system consists of six data bank interconnected by an integrator module to access at the different kinds of data stored in it: digital data, well logs curves, seismic field data and processed cross section, scanned technical documents.

The input/output and query operations can be made by UNIX workstations, PC or inside an Intranet/Internet web page.

DBU+ is the integration of two different independent experiences implemented in YPF and ASTRA prior to the merge of both company. These are the Data Base Upstream (DBU) oriented to the production, and the Argentine Corporative Data Bank (ABCD) oriented to geosciences. These two systems are presently in operation in the different fields of REPSOL-YPF.

With DBU+ a geoscientist can access from any remote station, in interactive graphics mode and at his fingertip, to any kind of geological, geophysical, petrophysics and reservoir information. The documents management system is the tool to visualize the well file and any type of scanned document.
The Sand-Rich and Mixed Sand-Mud Ramp Deep-Water Depositional Systems of the Apiuna Unit (Santa Catarina State, Brazil): a Challenge to Decrease the Unrecovered Oil
Authors: Basilici Giorgio , Martins Jorge Leonardo
Published: December 2007

A 3D model of an ancient sand-rich and mixed mud-sand ramp deep-water sedimentary environment, outcropping near Apiuna, Santa Catarina State, Brazil, is presented. This research contributes in the following way to the upstream sector of the petroleum industry: i) with a 3D conceptual model of reservoirs in ramp deep-water systems and ii) with 2D synthetic seismograms based on real outcrops.

The first contribution refers to a more refined 3D conceptual model for the reservoirs. The proposed architectural model is more complicated than the previous interpretations which saw the deposits of Apiuna unit as a channel-lobe system in a deep-water fan. In this new model, two type of ramp are recognized. One, sand-rich, is characterized by extensive sandy-sheet reservoirs, not linked to proximal channels and showing an apparent casuality of construction. The sandy sheets vary downcurrent their lithologic features as function of a density-stratified flow: debris flow s.l. in the lower part of the sedimentary flux and turbidity current in the upper part. The second type of ramp, mixed sand-mud, is characterized by a channel-levee complex. The two mentioned ramp systems represent the variation of the depositional environment controlled probably by tectonic-morphologic factors.

Construction of synthetic seismograms by using extensive 2D geologic models evaluated from outcrop data is the other part of this work. The properties needed for constructing the synthetic seismograms, which are densities and P-wave velocities of each stratigraphic unit, are evaluated from appropriate petrophysical tables. Synthetic seismograms are then used to qualitatively analyse the seismic response of a stratigraphic column. Correlation of each generated seismogram with the respective stratigraphic column allows identifying small-scale features not visible within the range of seismic frequencies.