Non-traditional Techniques for Microporosity Evaluation in a Low-Permeability Carbonate Reservoir from a Giant Oil Field Offshore Abu Dhabi, UAE
Jobe, Tiffany D.; Sarg, Rick; Steuber, Thomas; Shebl, Hesham
Recently, matrix related microporosity has been recognized as an important control on transmissivity and storage capacity of hydrocarbons. With the advancement of completion technologies for low-permeability reservoirs, quantifying the matrix-related micro-porosity, understanding pore size and pore throat distributions as well as tortuosity has become increasingly important. Traditional methodologies for porosity characterization developed for conventional reservoirs are often inadequate for low permeability, microporous reservoirs. This study focuses on microporosity characterization in carbonate mudstones and wackestones. Low permeability core plugs from a Lower Cretaceous aged reservoir were evaluated and 5 distinct reservoir facies were identified based on detailed core and thin section description. Porosity is estimated for each lithofacies by petrographic image analysis as well as a new technique for porosity determination from QEMSCAN® (quantitative evaluation of minerals and porosity by scanning electron microscopy) analysis (Jobe et al 2013, in prep). Estimated porosities are compared to measured porosity from a CMS-300® (core measurement system) automated permeameter. Furthermore, porosity and pore throat distributions are determined by Mercury porosimetry and Nitrogen gas adsorption experiments in order to capture both micro- and nanopore distributions. A comparison of porosities from each analytical technique is presented. In addition to porosity, the permeability and specific surface areas are measured and tortuosities are calculated. Results of the study show distinct differences in porosity, permeability, surface area and tortuosity among the lithofacies, despite their seemingly similar mudstone to wackestone textures. Pore size distributions indicate bimodal pore distributions that are in the micro to nanoporosity range. In general the porosities reported from Mercury porosimetry, Nitrogen gas adsorption and CMS-300® experiments agree with those determined by QEMSCAN® analysis, yet all are significantly higher than those reported by petrographic image analysis. This discrepancy indicates that there is a significant portion of micro- to nano- scale porosity not captured by traditional optical microscopy. Pore size and shape distributions, while different for each sample, agree qualitatively across all analytical techniques. Calculated tortuosities were also distinct for each sample; the samples with the most nanoporosity had the lowest tortuosities, while heterogeneous samples consistently had the highest tortuosities. The results of this microporosity evaluation indicate that each lithofacies has a unique set of values for porosity, pore size distribution and tortuosity. These parameters are what control fluid flow in the matrix and therefore the different lithofacies will have distinctly different fluid flow responses in a reservoir.
AAPG Search and Discovery Article #90163©2013AAPG 2013 Annual Convention and Exhibition, Pittsburgh, Pennsylvania, May 19-22, 2013