Petrophysical evaluation of the tight gas reservoirs in northern Mexico presents challenges for identifying overpressured gas zones when applying conventional techniques in laminated and fine grain sand zones. This paper presents case histories in which the magnetic resonance technology was used in its new T1 mode and describes the advantages of this new logging mode over the conventional T2 mode in gas reservoirs. The paper highlights the integration of all available petrophysical data for a particular field. This integration model compares the irreducible water saturation between the newly developed models, based on magnetic resonance data after its calibration to core, conventional logs, and production tests. Our integrated approach was used to analyze the data from different wells drilled in the field and to determine the best petrophysical parameters for any interpretation. The approach used was focused on identifying the best zones to be further evaluated, considering the different responses of all available log data from each well in the field. Permeability was derived from the Coates model using the magnetic resonance data after its calibration to cores. Results were then compared to actual production. For those wells in which only standard MRI logging information was available, the model was used to calculate the permeability and compare it to actual cores. Production test results were also compared to the evaluation prognosis and used to fine tune the interpretation model. The model was then used in other wells in the area for which few conventional log data were acquired. The integrated approach used with the new MRI acquisition technique benefits the operators by helping them to better evaluate and produce laminated tight gas reservoirs. The methods developed helps with making the right decisions regarding the need to acquire additional log data, with defining intervals for testing, and determining the size of the required hydraulic fracturing for production. Introduction In overpressured tight gas reservoirs, permeability is one of the critical parameters used to characterize the reservoir and to determine the best fracture design for maximizing its gas recovery. One of the options for obtaining reliable reservoir permeability is to cut cores, using conventional methods or by using wireline rotary coring techniques, and send these rock samples to a petrophysical laboratory for permeability measurements. This is usually a single point measurement. Conversely, because permeability ranges only from 0.001 md to 0.1 md in this tight gas field, pressure tests or build-up analyses have limitations. The use of magnetic resonance to determine the irreducible water saturation and permeability using the Coates relationship (Coates, et al., 1999) is proven to be a reliable option in this type of reservoir. This relationship relates the total volume of fluids to the nonmoveable irreducible fluids in the pore space to determine the permeability. It has given good results, especially in sandstones. The original Coates relationship is expressed as follows: Equation Where: K = Permeability f = MRIL Porosity MFFI = MRI Free Fluid Volume MBVI = MRI Bulk Volume Irreducible C = Coefficient dependent on reservoir type a, b= Exponents derived from NMR core analysis Typical values for the exponents in sandstones in the Gulf of Mexico are C=20 and a, b= 2 In general, the MRI permeability should initially be used to differentiate between good quality and poor quality reservoirs in a relative fashion. After calibrating to the MRI core analysis and defining the values of "C," "a," and "b," it can be used in its absolute form. It should be closely compared to the Klinkenberg permeability (air permeability corrected for overburden) measured in the laboratory (Marschall, et al., 1999).

Electric logs and borehole imaging were used to build a geomechanical model to predict wellbore instability during drilling and to optimize casing designs and completions to control sand production in the Burgos Basin. This paper describes how geomechanical models can explain several problems in drilling and completion during the development of some of the fields in Northern Mexico. The total stress tensor model, the pore pressure model, and the mechanical properties model are discussed. Validation of the model is a critical step before it can be applied to design new wells. The geomechanical model was used to design a new well and to optimize drilling, completion, and production techniques for the reservoir. The model was used to optimize the placement and orientation of perforations, evaluate proposed hydraulic fracturing designs, and select the critical draw-down to produce a well. Actual drilling, completion, and production events for the new well were analyzed, and conclusions about how the geomechanical model supported the complete design are also included in this paper. Introduction Several studies worldwide have confirmed that the optimization of non productive time related to borehole instability while drilling, the determination of the preferential permeability in naturally fractured reservoirs, the integrity of seals in geological faults, sand production potential, reservoir compaction and casing damage, are controlled by the geostatic in situ stresses, the pressure of the fluids in the pore spaces and the mechanical properties of the rocks. A geomechanical model for the field was built based on information from conventional and electric imaging logs in addition to the drilling information of the first exploratory well, F-1, drilled in the field. The model was validated predicting breakouts in the F-1 well and comparing them with rock failures observed in the caliper log, breakouts observed in the electric imaging log and with drilling problems related to wellbore instabilities. The geomechanical model for the field predicts well the observations and problems identified in the F-1 well during the drilling, completion (hydraulic fracture) and initial production of the well. A wellbore stability analysis during drilling and completion was performed for the F-1 well to predict the mud weight requirements during drilling to prevent large breakouts/washouts or lost of circulation problems and the required borehole pressure to prevent sand or formation flowing during the production phase. Furthermore, the lessons learned from F-1 were successfully applied to drill, stimulate and produce a new well, F-101. Geomechanical Model The project started collecting all the information related to planning, drilling and completion of the F-1 well. This well was drilled as a directional J-shape well to reach the final objective in the Jackson Formation, as presented in Figure 1. General information of the Field was reviewed (including surface seismic and maps), the structural model, standard and advanced wireline logs including dipole sonic and images acquired in the F-1 well, drilling and completion information (including daily reports, mud weight reports, well design schematic, leak off tests and Minifrac tests), pore pressure measurements in the reservoir, well geometry and formation tops.

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