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AAPG Bulletin


AAPG Bulletin, V. 103, No. 8 (August 2019), P. 1963-1978.

Copyright ©2019. The American Association of Petroleum Geologists. All rights reserved.

DOI: 10.1306/01171916527

Confocal laser scanning microscopy and automated petrographic image analysis in different rock types: Two-dimensional images capillary pressure curves estimation and three-dimensional porosity reconstruction

M. A. Caja,1 J. L. Pérez-Jiménez,2 M. F. León,3 and D. Acero-Allard4

1Geology, Geomechanics and Petrophysics, Repsol Technology Lab, Madrid, Spain; [email protected]
2Reservoir Characterization Laboratory, Repsol Technology Lab, Madrid, Spain; [email protected]
3Geology, Geomechanics and Petrophysics, Repsol Technology Lab, Madrid, Spain; [email protected]
4Schlumberger Reservoir Laboratories, Schlumberger Technology Corporation, Houston, Texas; [email protected]


In the past, determination of rock properties using image analysis relied upon petrographic transmitted-light images, but with limited success because of a lack of resolution and restricted computer processing power. A new technique that employs confocal laser scanning microscopy (CLSM) can be considered complementary to laboratory measurements and applicable to several samples, saving time and money and requiring only a limited amount of rock sample for analysis. We have studied several types of rocks with CLSM and fluorescent dye–impregnated thin sections. The two-dimensional scans of each thin section images is an area of 12 mm2, with a pixel size of 0.198 μm and were used to simulate capillary pressure curves for pore bodies and pore throats. The CLSM technique also enables three-dimensional (3-D) visualization of the rock porosity. The studied rock samples were taken from diverse oil and gas field reservoirs: case A, a conventional sandstone (15.1% porosity, 29.8 md permeability); case B, a tight sandstone (3.7%, 0.02 md); case C, an oolitic carbonate (9.6%, 0.1 md); case D, a rhodolithic algal carbonate (19.8%, 43.7 md); case E, dolomitized carbonate (17%, 21.7 md); and case F, a naturally fractured carbonate (2.4%, 0.6 md). Our results confirm that the CLSM technique can be applied to rocks of contrasting porosity and permeability to obtain computed synthetic capillary pressure curves faster than with conventional measurement methods. The technique quantifies different pore-body and pore-throat sizes and distributions, with the added ability to visualize 3-D porosity and to extract from thin section analysis petrologic properties.

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