The Control of fracturing and dolomitisation on 3D reservoir property distribution of the Asmari Formation (Oligocene-Lower Miocene),

Aqrawi, Adnan A.M.; Wennberg, Ole Petter

doi:10.2523/iptc-11191-ms

Cited by 2 publications

(1 citation statement)

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“…The unconfined compressive strength, UCS varied from 6.5-79.6 MPa and densities ranged from 2.39-2.59 g/cc. Aqrawi and Wennberg (2007) found that dolomitization in the Amari enhances permeability attributed primarily to the associated volume change.…”

Section: Introductionmentioning

confidence: 96%

Petrophysical Study of UAE Carbonate Outcrop at Jabal Hafit

Sondergeld

Wampler

Abdelghany

et al. 2016

SPE Annual Technical Conference and Exhibition

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Jabal Hafit consists of Tertiary outcrops that give insight into stratigraphic sequences and regional reservoirs in the Middle East. This study examines outcrops from various strata in the Rus, Dammam, and Asmari Formations varying from Early Oligocene to Eocene in age. These Formations exist throughout the UAE and Middle East and contain some large regional hydrocarbon reservoirs.This study examines porosity, permeability, mineralogy, NMR, MICP (mercury injection capillary pressure), and SEM images for 72 core samples. FTIR (Fourier Transform Infrared) mineralogy shows that these samples are calcite dominated carbonates with two strata being dolomite dominated. Sample porosities decrease linearly with increasing pressure and range from 0.47 to 27.26%. Klinkenberg permeabilities decrease linearly with increasing pressure for most samples, with some samples showing nonlinear pressure dependence indicating the presence of cracks. Permeabilities range from 0.0002 to 54.85 md. A porositypermeability correlation has been developed based on measured core data. The Reservoir Quality Index is used to identify similar reservoir flow characteristics and two flow zones have been identified across the three Formations. The second flow zone demonstrates some permeability pressure dependence. NMR shows bimodal pore distributions in some samples as well as extreme variability from layer to layer. A comparison of NMR, ϕ NMR , and Boyle's Law, ϕ He , porosities shows good agreement at porosity values lower than 10% with the ϕ NMR < ϕ He at larger porosities. The Free Fluid Model and Mean T 2 Model are used to estimate permeability from NMR data. Corrected T 2 cutoffs are determined from S wir via centrifuge method to define the correct Bound Volume Irreducible (BVI) and Free Fluid Index (FFI) for each sample. Measured T 2 cutoff times range from 2.38 to 598 ms. Calibrated and uncalibrated Free Fluid Model and Mean T 2 Model permeabilities are compared with measured core permeability values. For these samples, the Mean T 2 Model gives a better permeability estimate. SEM images reveal the bulk of the pores are equant in shape and document the existence of microporosity. Some MICP and NMR measurement capture the bimodal pore distributions.

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Section: Introductionmentioning

confidence: 96%