Antonio Luiz Serra de Souza

Particle Detachment Under Velocity Alternation During Suspension Transport in Porous Media

Flow of suspensions in porous media with particle capture and detachment under alternate flow rates is discussed. The mathematical model contains the maximum retention concentration function of flow velocity that governs the particle release and is used instead of equation for particle detachment kinetics from the classical filtration model. An analytical model for suspension injection with alternate rates was derived, and a coreflood by suspension with alternate rates was carried out. The modelling and laboratory data are in a good agreement, which validates the modified particle detachment model with the maximum retention function.

Integrated Modeling for 3D Geomechanics and Coupled Simulation of Fractured Carbonate Reservoir

Geomechanical models have multiple uses in reservoir management and field development planning. In this case study from a producing deepwater fractured carbonate reservoir (water depth approx. 1500m) we use the same geomechanical model to understand (i) why hydraulic stimulation failed to open a hydraulic fracture due to high minimum principal stress, (ii) what the limits of mud weights for drilling horizontal wells into the pressure depleted reservoir are, and (iii) investigate what the effect of pressure depletion and associated stress changes are on fault permeability, thereby providing an explanation for an observed early water-breakthrough. Multiple data sources, including structural seismic interpretation and Amplitude-versus-Offset (AVO) inversion, well-log measurements and rock-mechanics laboratory tests were combined in building a mechanical property model, and the computed stress state was calibrated with wellbore observations of breakouts directions, induced fractures and leak-off tests. Introduction Reservoir geomechanics has become an accepted technology for the petroleum industry during last decades. There are many benefits on improving geomechanical understanding, including: · A better characterization of reservoir volume deformation and impact on rock permeability (compaction and dilation); · Prediction of surface subsidence; · Reducing of risks of fault reactivation and out-of-zone hydraulic fracture propagation during waterflooding or other improved oil recovery process. In Petrobras, Reservoir Geomechanics is a fundamental tool for development of fields with large number of faults/fractures, which is the case of several offshore sandstone reservoirs in Campos Basin, as well as some carbonates fields. Here we discuss the development of a comprehensive reservoir geomechanics study in an actual field of the Campos Basin. The presented technology has been developed as part of the Technology Cooperation Agreement on Reservoir Geomechanics between Petrobras and Schlumberger. A similar study has been carried out for a sandstone field and presented at a SPE Conference (Souza et al, 2012). This multidisciplinary project has been developed with a team of geophysicists, geologists, reservoir and geomechanics engineers. An integrated approach involving seismic inversion, structural geology, rock mechanics and multiphase flow in porous media is used to build a 3D geomechanical model of an offshore naturally-fractured carbonate reservoir, Campos Basin, Eastern Brazilian Continental Margin. The first phase of the project involves auditing the data and building 1D Mechanical Earth Models (1D-MEM). These 1D-MEMs use data observations of stress directions and magnitudes (e.g. breakout directions, induced fractures, leak-off-tests, in combination with drilling experience and employed mudweights) for creating stress models along the well trajectory and are later used as calibration tool for the 3D geomechanical model. For the second phase a 3D Mechanical Earth Model (3D MEM) is built, by gridding the reservoir as well as over-, underand sideburdens, and populating the model with mechanical properties. Rock properties such as Young’s modulus, Poisson’s ratio, density, friction angle, unconfined compressive strength are distributed using a combination of well log observations, seismic AVO inversion models and rock mechanics test data (Herwanger and Koutsabeloulis, 2011). Pore pressure is also assigned based on seismic interval velocities calibrated with pressure observations (Dutta, 2002). The properties are developed based on

Injection of Dilute Oil-in-Water Emulsion as an Enhanced Oil Recovery Method for Heavy Oil: 1D and 3D Flow Configurations

Unfavorable mobility ratio and reservoir heterogeneities contribute to water fingering phenomenon that leads to relatively low oil recovery factors in heavy oil fields. Experiments have shown that injection of oil-in-water emulsions can be used as an effective enhanced oil recovery (EOR) method, leading to substantial increase in the volume of oil recovered. Capillary-driven mobility alteration of the water phase by emulsion drops leads to not only more uniform macroscopic reservoir sweep, but also a pore scale reduction in the residual oil saturation. Despite recent developments, fundamental aspects of dilute oil-in-water emulsion flow through porous media and its application as an EOR method are still not clear. Experiments were performed in a 1D flow configuration using silica sandpacks and sandstone cores to determine the effect of permeability, emulsion drop size, dispersed phase concentration and size of injected emulsion bank on the volume of displaced oil, a crude heavy oil from Campos Basin (

A comprehensive model for injectivity decline prediction during PWRI

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Quantitative Theory for Fines Migration and Formation Damage

20∘ API). X-ray computerized tomography images obtained during experiments in a Castlegate sandstone block in a 1/4 5-spot configuration revealed that emulsion acts both in the macroscale and pore scale, improving the macroscopic sweep and lowering the residual oil saturation.