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The current paper presents three analytical methods for evaluating the influence of parameter uncertainties in the wellbore failure process: FOSM (First Order Second Moment), FORM (First Order Reliability Model) and SEAM (Statistical Error Analysis Method). Results generated by Monte Carlo method are used as reference. These methods evaluate the probability of failure based upon reliability indexes. The paper also presents the results of a sensitivity study to establish the most important parameters that control wellbore instability. This is necessary in order to limit the number of calculations before establishing the probability of failure. The results demonstrate the importance of reducing uncertainties associated with the relevant parameters by means of careful testing procedures. Introduction Instabilities of wellbore walls may cause great operational problems during drilling. The proper evaluation of the operational window for the drilling fluid density is important to define the depths to set casing. Furthermore, the amount of wellbore wall collapse allowed to occur has large impact on the selection of hole cleaning system. Currently there is a great diversity of wellbore stability computer packages available. These computer simulators cover from simple linear elastic solid-like material behavior to poroelastic models and to elasto-plastic rock response. Some of these simulators can handle tridimensional geometries, physico-chemical rock-fluid interaction and thermal effects. Definitely, much progress has been made on this issue. However, these packages consider fixed, deterministic values for all input data. One of the barriers separating the available tools from the practical needs of the industry is related to the uncertainties associated with the parameters that control the wellbore stability. Random variations of the parameters that control wellbore stability (in situ stresses, rock properties, and pore fluid pressure) may occur along the wellbore. Relatively few studies have been carried out in order to take into account the uncertainties of input data in the evaluation of wellbore stability. Dumans1 presents two methodologies to consider parameter uncertainties in wellbore stability: Monte Carlo method and fuzzy set theory. Several parameter probabilistic distributions were used and the Monte Carlo method seemed to perform satisfactory. Teixeira et al.2 describe a probabilistic analysis for wellbore stability using Monte Carlo method and an elastic stress analysis associated with shear failure criterion to define the wellbore wall failure condition. Moos3 reports the use of a computer package also based in Monte Carlo method. In spite of its simplicity, the Monte Carlo method requires a great number of calculations and that precludes its use for generating results along the whole wellbore. The present paper presents the use of three analytical, probabilistic methods to wellbore stability problems. These methods, opposite to Monte Carlo method, are not based in random simulations. In spite of the approximate nature of these methods, their use is advantageous since a considerable smaller number of calculations must be performed. Initially, the three probabilistic methods are described. Next, a synthetic example is generated in order to demonstrate the potential of the methods. Comparisons are made with the Monte Carlo method. At the end, the results of a sensitivity study are shown in order to evaluate the most influential parameters. In order to evaluate the procedures for probabilistic analysis of failure around wellbores, a simple wellbore stability simulator4 was used. This simulator treats the rock as an elastic material and failure is calculated superimposing the elastic based stress distribution to a Mohr-Coulomb failure criterion for the rock. Failure mode in tension is also considered.

This paper presents a coupled chemical-hydro-mechanical model for the evaluation of the fluid behavior around an injector well taking into account insoluble salt precipitation (barium and strontium sulfate). A salt precipitation model is developed and coupled with the ion transport equation describing the ion movements and reactions through porous media. The finite element method has been used to obtain the solution for the coupling amongst the ion transport, the fluid flow and the mechanical response of the rock. A computer program has been developed to solve this highly nonlinear problem. Results of an experimental test1 carried out in a sand pack with the analysis of the barium sulfate crystal growth was selected as benchmark to test the computer program developed using the methodology described above, showing an excellent agreement between the numerical and the experimental results. Introduction The water produced during oil recovery, demands expensive treatment before being discarded due to environmental issues. One economical alternative to handle this formation water is its re-injection into the producing reservoir, or alternatively into another permeable formation. However, water injection program may have low efficiency due to formation damage around the injected wellbore. This formation damage is the result of interaction between the injected fluid (chemical composition, solid particles and percentage of oil emulsion) and the rock formation. In this work, we focus our attention to the damage caused by the differences between the chemical composition (Table 1) of the injected fluid and the formation fluid. This fluid mixing process may generate the precipitation (scale) of some salts in the rock pores, and consequently, causes a permeability reduction. The most commonly found scales are the carbonate and sulfate salts of calcium, barium and strontium. Carbonate scale are softer and tend to be acid soluble, i.e., can be removed from the wellbore through an acidification operation. The concern with sulfate scale is justified due to their relative hardness and low solubility, that is, cannot be dissolved easily in the field. Another important issue is that the fluid is subjected to a high temperature variation during injection process. Initially, the water is injected at high temperature (40°C). During the water depth the fluid is cooled, for ultra-deep wells, it could arrive to a temperature in order of 3°C. After that, due to the geothermal gradient, the fluid is heated again, arriving to temperature around 115°C for deep reservoirs. This high temperature variation increases the amount of salt precipitation. Formation damage models that include chemical effects have already been developed2–7. Malate3 presents a mathematical model of silica deposition during the reinjection of seawater using the method of characteristics. Walsh et al.4 developed a geochemical model to simulate the reactive fluid flow in porous media. Wu and Sharma5 extended Walsh's model to include the migration of precipitate solids. Chang and Civan6 developed a mathematical model to simulate the permeability alteration mechanisms caused by various physical and chemical interactions between fluids and reservoir rocks. Araque-Martinez and Lake7 developed a model to characterize the geochemical changes that occur in a permeable medium with flow and reaction under a consistent kinetic formulation. In the current work, a salt precipitation model is developed and coupled with an ion transport equation describing the ion movements and reactions through porous media. The finite element method has been used to obtain the solution for the coupling amongst the ion transport and reaction, the fluid flow and the mechanical response of the rock. It is followed a different approach from the papers mentioned above. The developed model simulates injection under conditions, of high temperature and pressure variations and high salinity.

Geomechanics has become an important tool for engineers and geologists, with classical applications in wellbore stability, sand management, and hydraulic fracturing. However, unconventional shale reservoirs cannot be evaluated with traditional models or on the basis of simple relationships between isotropic elastic properties, far-field stresses, and reservoir and mechanical properties. These plays are geologically complex and the reservoirs are heterogeneous in nature. Wells need to be hydraulically fractured for stimulation and, in a complex tectonic environment, the rock fabric and in situ stress strongly influence this process. We discuss a new methodology developed for stress modeling, taking into account the tectonic environment. We present a case study for the Vaca Muerta formation in Argentina. The obtained results contribute to the understanding of stress distribution in unconventional reservoirs.

Several Petrobras fields in Campos Basin are soft sandstone with a large number of faults, which demands a careful reservoir geomechanics study in order to maximize their production and minimize geomechanical risks. Those risks are associated with compaction and/or dilation, subsidence and in special with fault reactivation due to water injection, which can lead to a connection between different layers and reservoirs. The object of this study is a faulted turbidity reservoir in Campos basin where a water injection project has started. The Mechanical Earth Model (MEM) was developed. It was identified that the planned injection pressure would increase the risks for fault reactivation, and recommendations for a safe water injection project was obtained. Special emphasis is on factors that may have enhanced leakage pathways at some point during injection, reducing its effectiveness and bringing other related risks. Reservoir performance and associated reservoir deformation was estimated. The predicted stress and strain changes that were induced by production/injection were used to assess the wellbore stability, faults reactivation potential, cap rock integrity and rock fracturing. Understanding of the various potential processes and being able to predict the field behavior are critical to the optimal management of the reservoir for maximum productivity and recovery.