Petrophysical Study of UAE Carbonate Outcrop at Jabal Hafit
- Carl H. Sondergeld (University of Oklahoma) | Jeff Wampler (University of Oklahoma) | Osman Abdelghany (United Arab Emirates University) | Al Anin (University of Oklahoma) | Chandra Rai (University of Oklahoma) | Mark Curtis (University of Oklahoma)
- Document ID
- Society of Petroleum Engineers
- SPE Annual Technical Conference and Exhibition, 26-28 September, Dubai, UAE
- Publication Date
- Document Type
- Conference Paper
- 2016. Society of Petroleum Engineers
- 5 Reservoir Desciption & Dynamics, 1.6.9 Coring, Fishing, 5.2.2 Fluid Modeling, Equations of State, 5.2 Fluid Characterization, 1.6 Drilling Operations
- Carbonate, Petrophysics, Permeability, NMR, Porosity
- 3 in the last 30 days
- 195 since 2007
- Show more detail
- View rights & permissions
|SPE Member Price:||USD 5.00|
|SPE Non-Member Price:||USD 28.00|
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 porosity-permeability 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, ?NMR, and Boyle's Law, ?He, porosities shows good agreement at porosity values lower than 10% with the ?NMR < ?He at larger porosities. The Free Fluid Model and Mean T2 Model are used to estimate permeability from NMR data. Corrected T2 cutoffs are determined from Swir via centrifuge method to define the correct Bound Volume Irreducible (BVI) and Free Fluid Index (FFI) for each sample. Measured T2 cutoff times range from 2.38 to 598 ms. Calibrated and uncalibrated Free Fluid Model and Mean T2 Model permeabilities are compared with measured core permeability values. For these samples, the Mean T2 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.
|File Size||7 MB||Number of Pages||13|
Logan, W. D., J. P. Horkowitz, R. Laronga and D. W. Cromwell, 1998, Practical application of NMR logging in carbonate reservoirs, SPE 51329, SPE Reservoir Evaluation & Engineering doi: 10.2118/51329-PA
Whittle, G. L., A. S. Alsharhan and W. M. Z. El Deeb, 1996, Facies analysis and early diagenesis of the middle-late Eocene Dammam Formation, Abu Dhabi, United Arab Emirates, Carbonates and Evaporites, v. 11, n. 1, 32-41, DOI: 10.1007/BF03175783.