bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Comparison of Design Placement Methodologies for Horizontal Open Hole Gravel Pack in Multizone Completion Projects
Authors: Loureiro B. V. , de Magalhaes J. V. M. , Martins A. L. , Calderon A. 
Published: May 2009

Abstract
Horizontal Open hole gravel pack is the conventional sand control technique for offshore non consolidated reservoirs in Brazil. Gravel pack placement requirements include the design of pumping pressures inside the operational window formed by the minimum pump rate to avoid premature rat hole screen-out and maximum pump rate to avoid formation fracture. Some special projects require additional equipment to provide selective completion – External casing packers installed at different positions along the production screen aim the isolation of certain reservoir zones. In these cases, gravel pack placement present an additional constraint – operational pump rates should be high enough to avoid alpha wave sedimentation around the packers in order to assure sealing after the packer inflation process. Traditionally, design criteria consider a minimum critical velocity to avoid sand deposition.
The specification of minimum flow for cleaning the ECP, and prevent the deposition of sand in the annular space can be obtained from different criteria. Two methods are proposed to analyze the problem: a constant velocity and a constant shear stress approach. The major contribution includes CFD – computational fluid dynamic simulation of the 3D flow around the packer, using a finite volume method. The methodology based on the estimation of the local shear stresses at the interfaces, suggests less conservative numbers which allows effective gravel pack placement in selective completion projects in narrow operational windows. An illustrative case study with field validation is provided.
Reservoir and Operational Analysis for Steamflooding on Thin Oil Reservoirs
Authors: Gurgel A. R. , Barillas J. L. M. , Rodrigues M. A. F. , da Mata W. , Dutra T. V. 
Published: May 2009

Abstract
This work has the objective of analyzing the influence of some parameters in the continuous steam injection simulation in thin homogeneous reservoirs. Thin reservoirs can be defined as those with thickness between five and fifteen meters. Through sensibility analysis, a study was realized on the influence of operational parameters such as distance between wells and steam rate on cumulative oil production and oil recovery. The study has the purpose of incrementing oil recovery in thin reservoirs similar to those found in Potiguar Basin, Northeast Brazil. The analysis was done using the software STARS- 2007 (Steam Thermal Reservoir Simulation) of group CMG (Computer Modeling Group). Results showed that there is a specific condition of thickness, a steam injection rate and distance between wells that optimizes the oil recovery of the process.
Prediction of Pressure Losses in Drilling Fluid Flows in Circular and Annular Pipes and Accessories
Authors: Scheid C. M. , Calcada L. A. , Rocha D. C. , Aranha P. E. , Aragao A. F. L. , Martins A. Leibsohn 
Published: May 2009

Abstract
This article details an extensive experimental study aiming the evaluation of friction losses resulting from the flow of 4 different drilling fluids in use in deepwater operations through pipe and annular sections, besides accessories such as tool joints, bit jets and stabilizers. After a data analysis process, it was possible to compile a set of equations for prediction of relevant hydraulic calculations, such as: hydraulic diameter for annular flows, friction factors for turbulent pipe and annular flows and discharge coeeficients for accessories.
Energetic Optimization to Heavy Oil Recovery by Electromagnetic Resistive Heating (ERH)
Authors: de Oliveira H. J. M. , Barillas J. L. M. , da Mata W. , Dutra T. V. 
Published: May 2009

Abstract
Electromagnetic resistive heating (ERH) is a thermal stimulation technique in which the electrical current passes through formation increasing the original temperature by Joule effect. Thus, greater is the electrical current intensity, highest reservoir temperatures are reached. This method is much influenced by electrical conductivity of the interested zone mainly due to electrical conductivity of connate water. So, water is directly heated by Joule effect and oil is heated by both conduction and convection heat transfer. In this work, it was studied a combination of time heating without production and heating with concomitant production, which provides a greater economic advantage depending on energy price used and oil price produced, since oil production is increased due to heating provided by ERH.
This method is suitable for use in wide kinds of reservoirs, with different characteristics of reservoir thickness, injectivity, formation permeability, formation porosity, pressure, depth, temperature, oil saturation and oil viscosity. Depending on the energy magnitude delivered to reservoir and formation pressure, this method can be an alternative to in situ steam generation. For offshore productions systems, where the platform surface is limited, the ERH becomes a quite attractive thermal method, been an alternative to steam flooding avoiding heat losses in pipes.
A good strategy for ERH process is, first of all, to choose an electrodes configuration, and after, to control the energy delivered to reservoir, by electrodes voltages, depending of desirable oil rate and temperature obtained in electrodes zones. Electromagnetic resistive heating may produce even better results with water flooding to displace the mobile oil bank after electrical heating, regulating the reservoir pressure and adjusting the electrical conductivity of the system. So, it was possible to optimize the operational parameters to maximize the oil recovery with minimal energy requirement, resulting in an economic advantage.
In this work, it was studied an application of Electromagnetic Resistive Heating in a reservoir with similar characteristics of those found in Brazilian Northeast Basin. The obtained results can be extrapolated to others important applications, for example, offshore heavy oil reservoirs, where, actually, there is no available technology to exploit them.
Influence of Tectonic Stresses in the Permeability of Petroliferous Reservoir in Potiguar Basin, Brazil
Authors: Araújo J. S. , Vieira M. M. , Bezerra F. H. R. 
Published: May 2009

Abstract
Rock permeability is sensitive to the deformation caused by the stresses acting in oil reservoirs. These stresses can be either tectonic, generated mainly by the migration of the lithospheric plates, or lithostatic, caused by the weight of rock layers. Under reservoir conditions, stresses produce anisotropies in the pore spaces. Thus, the recognition of the relation among pore distribution, permeability and stress is important for decisions on planning, development and exploitation of oil reservoirs. The main objective of the present work was to study the relation between tectonic stresses and permoporosity of a reservoir analog in the Açu Formation, Potiguar Basin, Brazil. Oriented plugs were collected, according to the directions of the operating stresses in the basin; these directions were derived from earthquake data (focal mechanism), wells (breakout and anaelastic strain recovery - ASR), fault analysis, joints and dissolution structures, in Quaternary rocks less than 1.0 Myr. From these methods, it was concluded that the preferential direction of the maximum horizontal stress (SHmax) in Potiguar Basin ranges from EW to NW. An outcrop analysis led to the identification of seven lithofacies from which the samples were collected to be used in petrophysical and petrographic characterization. In qualitative terms, it was observed that the porosity found in thin sections is predominantly intergranular, followed by the intragranular (mainly in the interior of the feldspars), inter-crystalline (between the calcite crystals), and oversized types. The petrophysical data indicate that there is no significant difference between porosity and permeability values in both stress directions (SHmax and Shmin). Nevertheless, when porosity values obtained from the description of thin sections are analyzed, it is observed that the highest values are found along the direction of maximum stress. A possible explanation for this discrepancy with petrophysical data is the impossibility of pointcounting, in contrast with the porosimeter, in quantifying microporosity present in diagenetic clays. The foregoing data afford no evidence of the influence of tectonic stress over porosity and permeability in the Açu Formation outcrops. Permoporosityanisotropy, if present, may be caused by other factors such as lithofaciology, that is, sedimentary depositional conditions.
Optimization of Operational Parameters on Steamflooding With Solvent in Heavy Oil Reservoirs
Authors: Galvao E. R. V. P. , Rodrigues M. A. F. , Barillas J. L. M. , Dutra T. V. , da Mata W. 
Published: May 2009

Abstract
The process can be understood as a combination of a thermal method (steam injection) with a miscible method (solvent injection), promoting, thus, reduction of interfacial tensions and oil viscosity. When co-injected with steam, the vaporized solvent condenses in the cooler regions of the reservoir and mixes with oil, creating a zone of low viscosity between steam and heavy oil. Mobility of the displaced fluid is then improved, resulting in an increase of oil recovery and oil rates. To better understand this improved oil recovery method, a numerical study of the process was done contemplating the effects of some operational parameters (distance between wells, steam injection rate, solvent type and injected solvent volume) on cumulative oil produced and oil rates. Simulations were performed in STARS (CMG, 2007.11).
Semi synthetic model was used in this study and some reservoir data were obtained similar to those found in Brazilian Potiguar Basin. The method presented good performance for heavy oil reservoirs with approximately 200 m depth, porosity between 20% and 30%, vertical/horizontal permeabilities ratio of 10% and thickness around 30 m.
It was found that injected solvent volumes increased oil recovery and oil rates. Further, the majority of the injected solvent was produced and can be recycled. For applications of optimized model with oil viscosities of 300 cP, 1000 cP and 3000 cP, the most important oil recovery was obtained for the lightest one (300 cP), while for 1000 cP and 3000 cP, the final recovery was practically the same.
The high initial productions achieved by models that use solvent as an advanced recovery method have normally a significant impact on the operation economics, because early production suggests that fluids injection (steam and solvent) can be interrupted earlier. On environmental point of view, solvent injection can provide a reduction of energy and also a reduction in water consumptions for steam generation, having diminished Green House Gases (GHG) emissions. Also it is important to emphasize that the higher oil rates presented by these models can generate an earlier financial return and, by consequence, a project with a good economical viability.
Water Injection With Fracture Propagation Pressure
Authors: Costa O. J. , Muñoz Mazo E. O. , Schiozer D. J. 
Published: May 2009

Abstract
Water injection is a valuable method for produced water disposal and for reservoir pressure support. A disadvantage of water injection operations is the injectivity loss which can occur due to rock and fluid characteristics, formation damage caused by fines migration and by oil and solid particles present in the water. Optimal injection rates can't be achieved when injectivity loss occur. Nevertheless, the injectivity loss can be mitigated by water injection with fracture propagation pressure (IFPP) which aims to restore injection capacity.
To study this process, a geo-mechanical simulator for fracture modeling combined with a commercial reservoir simulation package is used to model and to optimize the operational conditions of water-injector wells. The fracture is represented by a virtual horizontal well and analytical formulations for hyperbolic decline of permeability represent the effect of formation damage around the injector well.
This paper aims to study some water injection cases to verify in which situations the IFPP use is convenient. The simulation model studied is a synthetic reservoir with a five-spot pattern. Three scenarios are considered with oil type variation (41, 31 and 21 API degrees).
Those scenarios are proposed to reproduce some possible situations that can happen in real field, where formation fracturing pressure can be reached by the effect of the injectivity loss or due to rock and fluid characteristics. The IFPP acting is evaluated using the net present value (NPV) and cumulative oil and water productions.
The results showed that the IFPP study becomes into an optimization problem of injection rate, where the fracture can or cannot occur. It is shown that IFPP, in general, anticipates oil production for cases of intermediate and high oil viscosity, turning a quite advantageous method. Studies in light oil indicate that the technique is only interesting when there is significant injectivity loss, which the IFPP aids in injectivity restoration. It is shown that IFPP can be advantageous, not only in cases where injectivity loss occurs, but also in cases without injectivity loss, in order to anticipate the oil production.
New Approach to Integrate Reservoir and Geological Information in Complex Fluvial-Stratigraphic Environments to Determine Potential Areas for Water Injection Processes
Authors: Sandoval J. R. , Soto C. , Pérez H. , Sandoval J. , Trujillo M. , Castro R. , Gomez V. , Cárdenas F. , Rodriguez E. 
Published: May 2009

Abstract
The geological, economic, and strategic conditions which make the discovery of large petroleum reservoirs a more risky and costly undertaking has resulted in having to consider mature fields and to conclude that the geology and the properties of fluids have an incidence in the final recovery of each reservoir, and that by understanding these factors it is possible to improve the recovery factor. The Lisama Field is located in the basin of the Middle Magdalena Valley, in Colombia, and is operated by ECOPETROL S.A. It is characterized by a complex of fluvial channels with thicknesses of between 10 and 20 ft, a restricted lateral continuity, lateral and vertical changes in the type of rock and depleted producing sands; this resulted in the need for new exploitation strategies which would allow the optimum recovery of the remaining reserves of the field. From a technical screening based on the properties of the rock, fluids, and the reservoir, the review of analogue fields worldwide and the experimental feasibility evaluated in the laboratory, the implementation of a water injection process resulted in a favorable method to be applied to the Lisama Field.
Geological, petrophysical, fluids, and production information was integrated during the identification and selection of areas and stratigraphic intervals with the best characteristics for the implementation of the water injection process. Zone Quality Factor maps, isochors, average thickness and percentage of sand tied to stratigraphic correlations and reservoir rock-type thickness maps were analyzed to obtain the spatial distribution of the more powerful, continuous channels, with more effective pores systems, which, integrated with the production analysis, resulted in the delineation of the areas of interest.
The prediction of the behavior of the water injection and the expected recovery of oil was obtained by means of an analytical and numerical simulation of the injection patterns as established.
An Application of Feed Forward Neural Network as Nonlinear Proxies for Use During the History Matching Phase
Authors: Sampaio T. P. , Ferreira Filho V. J. M. , de Sa Neto A. 
Published: May 2009

Abstract
Reservoir simulation is an important tool used in the industry for reservoir management. While developing a field, a reservoir simulation model is used as a decision tool to select the best development scheme and also to forecast the oil, gas, and water production expected for the field. Uncertainties are much higher at the early phases and, when production data are gathered during the field development phase, most of the time the initial reservoir simulation model needs to be reviewed once the field observed data is not as the same as the predicted by the model. Some of these uncertainties of these input parameters are related to the reservoir rock reservoir heterogeneities.
History matching techniques are used by reservoir engineers to mitigate/minimize the difference between the observed field data and the predicted data and thus assessing the uncertainties. When reservoir models become too big in terms of number of cells and features, the elapsed simulation time increases very much, making the history matching process very cumbersome and, in some cases, very difficult to achieve in an acceptable time. Parallel processing features of some commercial simulators can perform lots of simulation runs at the same time but cannot address and cannot solve the problem in a proper way.
This paper presents an alternative proposition to speed up the history matching process: the application of feed-forward neural networks as nonlinear proxies of reservoir simulation. Neural networks can map the response surface in multidimensional spaces of a reservoir model (i.e. water production, bottom hole pressure etc.) or of an objective function with few number of simulations. The mapped response is then used as a substitute of reservoir simulation runs during the history matching process. The focus of this work is to shown the steps of choosing the best number of hidden layers, the neurons and the training method. An application case is presented using the workflow presented is this work and showing the validity of the proposed methodology for this complex nonlinear problem.
Relative Contribution to Fluid Flow From Natural Fractures in the Cantarell Field, Mexico
Authors: Cruz L. , Sheridan J. , Aguirre E. , Celis E. , García-Hernandez J. 
Published: May 2009

Abstract
In the Cantarell field in Mexico oil is produced primarily from naturally fractured carbonate reservoirs. These types of reservoirs are among the most difficult to develop given the uncertainties associated with detection and characterization, both locally in the well and regionally in the field, of the fracture networks that predominantly control fluid flow. Additional complexities result from difficulties understanding matrix-fracture interactions.
In the last few years, the oil-water contact in the Cantarell field has been advancing, and this has considerably reduced the oil window zone. One likely explanation is that the natural fracture network (which provides most of the permeability in the field) favors production of water and gas over oil. This new challenge has forced Petróleos Mexicanos (PEMEX E&P) to make new efforts to characterize their naturally fractured carbonate reservoirs and improve their reservoir models.
Using the critically-stressed-fault hypothesis, which assumes that the faults and fractures that are hydrologically conductive today are those that are critically stressed (active) in the current stress field, GeoMechanics International (GMI) analyzed image logs of over 20 wells in detail, and constructed a geomechanical model of the Cantarell field, to define the role of the fracture network in fluid flow. In a previous study, GMI used all available data, including seismic data, caliper logs, image logs, electric logs, drilling reports, sedimentological analyses of cores, and regional tectonic studies, to develop a comprehensive geomechanical model of the field. We then used and complement this model in conjunction with all available image logs to predict the orientations of the most and least critically stressed (hence permeable and impermeable) fractures.
The results have been effectively used to improve well trajectories both to minimize costs and to optimize production throughout the life of the reservoir. The results have been particularly useful in horizontal wells, where preventing water production requires avoiding steeply dipping fractures that are critically stressed.
The Use of Well Strengthening for Coping with Losses During Precompletion Operations Prior to Horizontal Open Hole Gravel Pack in Campos Basin Deep Waters
Authors: Pedroso C. A. , Denadai N. J. , Coutinho P. C. , Pinheiro C. 
Published: May 2009

AbstractThe use of the alpha and beta wave technique for a successful Horizontal Open Hole Gravel Pack is based upon a well without, or with minimum, losses. In this case, the gravel particles will be adequately carried to the expected point of deposition. So, in case of any mud losses, both while drilling the reservoir or during pre-completion operations, an efficient loss control method should be used, in order to allow the best packing of the screen with gravel particles.Besides a brief revision of current techniques, this paper details a well succeeded loss control strengthening operation, when water based drilling fluid was injected during the pre-completion operations of a production well with long horizontal section in Campos Basin.After the displacement of the water base drilling fluid 9,4 ppg by completion fluid (brine) 9,4 ppg, the well started to lose about 15 bph of fluid. Based upon solid previous experience, an acceptable limit for WBM losses is about 2 bph. The well was reconditioned with WBM, lowering the losses for 5 bph, still too high. So a LCM pill was injected into the formation, above fracture pressure, using the "sealing fracture method". This procedure resulted in a well without any losses, which allowed the displacement by brine, the running of premium screens and complete the pumping of HOHGP without any incidents.
The Use of Saturated Fracturing Fluid to Cope With Hydrate in Gas Wells Located in Ultradeep Waters
Authors: Pedroso C. A. , Denadai N. , Pinheiro C. 
Published: May 2009

Abstract
A potential problem when fracturing gas wells in deepwaters is the risk of hydrate formation during the flow for cleaning the well.
Some alternatives have been used, such as the pumping of alcohol (methanol or ethanol) in the WCT (wet christmas tree) down the chemical lines or the postponement of the cleaning for some months, counting on the gravitational segregation of the fluids in the reservoir. In some cases, these solutions are not enough. In these cases, a possible solution is the combination of a saturated fracturing fluid together with a saturated brine, what reduces the hydrate formation envelope. This solution can be used in conjunction with other providences, such as the use of alcohol or glycol, sub-surface chokes, etc
The present work describes the steps for the development of a fracturing fluid based on saturated brines and the planning, execution and evaluation of fracturing jobs performed in gas wells located in water depths that ranges from 840m to 1950m.