NMR T2 Distributions in the Eagle Ford Shale: Reflections on Pore Size

Abstract

Production of oil from organic shale reservoirs is a function of porosity, hydrocarbon saturation, pore pressure, matrix permeability, and hydraulic fracture surface area plus fracture conductivity. Hydraulic fracture surface area, porosity, saturations and pore pressure dominate initial production rates. Matrix permeability becomes increasingly important in sustaining production later in time. Permeability measurements to oil from organic shale core samples are not commercially available today. However, permeability to oil is believed to be a function of pore throat size, wettability, and water saturation, the same as a conventional reservoir. This work investigates pore size, wettability, and expelled hydrocarbon volumes using log and core-based nuclear magnetic resonance data from the Eagle Ford Shale focused on the comprehensive evaluation of one well. Comparisons with core porosity measurements, scanning electron microscope images (SEM) and mercury injection capillary pressure tests (MICP) are compared with the nuclear magnetic resonance (NMR) interpretation for calibration and validation. The NMR T 2 distribution is partitioned into regions of bound and producible free fluid. Two types of pore systems are present in the Eagle Ford Shale; kerogen-hosted (OM) and inter/intra particle (IP). Bore hole logs indicate the upper Eagle Ford Shale is dominated by IP porosity, and the lower Eagle Ford Shale is dominated by OM porosity. Core NMR indicates OM pores are hydrocarbon wet while IP pores have mixed wettability. Core pore fluids are not representative of in-situ conditions as the lighter portion of the hydrocarbons have been expelled during core recovery. Comparison between log and core measured NMR allows the quantification of the expelled hydrocarbon-those zones with the "best" producibility. Understanding which portion of a shale reservoir contains producible fluids impacts target zone selection.

Experimental Study on Water Sensitivity Difference Based on Oiliness of Porous Medium Rock

“…Therefore, the distribution of the multiple exponential decay processes in rocks which are T 2 spectrum means the pore size distribution of the core. The pore throats reflected by T 2 spectral line of core of target block are mainly divided into three categories: clay-bound water pore, capillary-bound water pore, and free fluid pore [14,15]. T 2 spectrum cut-off value is obtained from empirical value and chart method.…”

Gas Production from Gas Condensate Reservoirs Using Sustainable Environmentally Friendly Chemicals

“…A shift of the relaxation time into the right side (higher relaxation times) indicates an improvement in rock conductivity, while if the T2 profile is shifted into the left side (lower relaxation times), that can indicate that damage has been induced into the considered rock. Usually, hydraulic fracturing treatment results in enlarging the pore sizes, and therefore, the NMR profile will be moved toward higher relaxation times [22]. In tight gas reservoirs, the sustainability of gas production can be quantified by studying the pore network.…”

Nano-Scale Pore Structure and Fractal Dimension of Longmaxi Shale in the Upper Yangtze Region, South China: A Case Study of the Laifeng–Xianfeng Block Using HIM and N2 Adsorption

“…Many high-resolution techniques have been applied to study the pore structures in shale with low porosity and low permeability, large parts of which are nanoscale pores (pore diameter of less than 100 nm). Based on previous studies, all of the following methods have achieved good results: Scanning electron microscope (SEM), Nano-CT, helium ion microscope (HIM), mercury intrusion, gas adsorption, nuclear magnetic resonance (NMR), and small-angle and ultra-small-angle neutron scattering (SANS and USANS) [8,[23][24][25][26][27][28][29]. In particular, SEM and N 2 adsorption are the most frequently used techniques, and both meet the demands of direct observation and quantitative analysis [30].…”