New Integrated Applications Using T1 and T2 Modes of Magnetic Resonance in Tight Gas Reservoirs: A Case Study From Northern Mexico

Abstract

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).