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.

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During produced water reinjection into an oilfield, the formation near the wellbore is progressively damaged due to total suspended solids (TSS) and oil particles in the injected water (OIW). This typically increases the bottom-hole injection pressure over time. Furthermore, if the water is injected in the oil zone, the initial bottom-hole injection pressure may already be high from the start due to water mobility constraint and oil viscosity. This study aims to model the generation of hydraulic fractures induced under different conditions, their geometrical characteristics and corresponding development over time. Such information is key to reservoir simulation for the secondary oil recovery and to reservoir integrity assessment. Four disciplines are integrated into the proposed workflow: reservoir flow simulation, formation damage modeling, reservoir geomechanics, and the simulation of hydraulic fracturing. First, a sector model around an injector well is extracted from the full-field reservoir simulation of the case-study reservoir. In the reservoir flow simulation, a formation damage model is implemented, calibrated from injection rate, bottom-hole pressure, TSS and OIW actual data. At specified time steps, the flow simulator passes pore pressure profiles of the sector model to the geomechanical simulator, which computes the corresponding changes in stress and deformation. The updated in-situ stress field, in combination with the petrophysical model applied for the flow simulation, is provided to the hydraulic fracturing simulator, which tests for the development of the hydraulic fracture and computes its geometry. The resulting hydraulic fracture is mapped back into the reservoir flow model to account for the local increase of permeability of the cells hosting the fracture. The workflow then enters into a loop starting again with the flow simulation, and the further development of the fracture under changing conditions is tested and modeled. The proposed workflow was successfully applied to an injection well in an offshore field. Four scenarios considered different initial formation saturation, injected fluid viscosity and the conversion of a producing well into an injector. Multiple fractures with different characteristics, fully contained inside the reservoir, were predicted for each scenario and gave insights into the hydraulic fracture development during produced water reinjection. The proposed method and workflow have the potential to significantly improve the reservoir simulation of the water injection process for secondary recovery or pressure maintenance by providing insights into how induced fracture geometries will influence the injection pressure and reservoir sweep efficiency. It also may provide valuable information to assess the integrity of reservoir cap rock during produced water reinjection.

In the southern region of Mexico, PEMEX along with Schlumberger-IPM is currently drilling deep wells into the Mesozoic Era reaching depths between 6000 to 7000 meters. The challenge of drilling into these reservoirs lies in the depositional environment, including the presence of salt domes, strong dipping layers, heavily faulted Tertiary formations and abnormal high pressures and temperatures. This paper presents a case study where a joint Geomechanics and Drilling approach was put in place to solve an emergential drilling problem in this Area. Although the complex structure, the previous drilling experience at this specific field, called Pache, showed good drilling performance and no mayor events were experienced. Nevertheless, several serious events occurred during the drilling of the 12–1/4-in hole, including stuck pipes events, which lead to two sidetracks and loss of the expensive downhole tools there were un-fishable. After analyzing operational practices and offset field characteristics it was decided to re-evaluate the geo-mechanical model, geology and geophysics in order to identify the mechanisms which caused the problem. As part of the analysis after the second sidetrack, an acoustic anisotropy tool was intentionally run, since the cavings reported during the operations indicated multiple rock failure evidences. This study shows the methodology used to evaluate and determine the possible mechanisms of borehole instability as well as the recommended drilling practices and optimum mud weight adopted to avoid or minimize packoff events. It was proved that a timely data acquisition together with an integrated drilling and geosciences analysis can indeed support real time operations, understanding the root causes of the problems and proposing adequated solutions. In this case study, a 3 MMUSD non productive time problem was solved in an intense 3 days analysis. Evidently, appropriate data and a multidisciplinary team are needed to put in place such solutions. Introduction This study refers to a field called Pache, located in South Mexico, Tabasco. The suggested drilling locations at this field are based on a Post-Stack Time Migration Cube. The quality of the seismic data is fair and processing reveals velocity and migration issues. Figure 1 presents some processing results and interpretation, useful to introduce the structural complexity of the field.

Drilling horizontal wells in shallow and poorly consolidated reservoirs in deepwater scenarios involves risky operations due to the narrow mud weight window. Risks include severe drilling fluid losses, wellbore instability, and fault reactivation, which, in the worst case, may connect reservoir to the sea floor. This work presents a case study of risk reduction based on geomechanics, which includes concepts of fault reactivation while drilling, permitted plastified area around the wellbore, and fit-for-purpose data acquisition, which allowed a recalibration of the model and timely changes on the drilling plan. The study started with a full 3D geomechanical characterization, which is an advanced way to determine stress distribution in a field, in particular, along the faults. Based on this study, it was possible to locate and avoid zones of higher risks of losses and fault reactivation, mitigating drilling risks. From the study, it was also possible to identify the main uncertainties of the model, which allowed a fit-for-purpose data acquisition plan. The most important missing information was a calibration point for the minimal horizontal stress in the reservoir. Previous drilling experience in the area and geomechanics modelling were not conclusive about losses mechanisms, and the upper limits for horizontal drilling were also not clear. In addition, borehole instability had been shown to be an issue on offset wells; therefore, lower limits for drilling were unclear too. It was decided to drill a pilot hole down to the reservoir, set a packer in the caprock and perform a series of minifrac tests. The measured minimal horizontal stress in the reservoir was revealed to be lower than initially expected, which implied the need to recalibrate the model and make important adjustments to the drilling plan. The model was recalibrated and the safe mud weight window was found to be even narrower. It was identified that a lower and unprecedented mud weight had to be used in the horizontal section, which was an additional risk. To evaluate this risk, the concept of permitted plastified area around the wellbore was used, and a lower mud weight was selected under a risk analysis manner. Based on the study, drilling risks were mitigated and horizontal drilling was performed successfully, with minimal losses and controlled wellbore collapse.