Sondergeld, Carl H. (University of Oklahoma) | Wampler, Jeff (University of Oklahoma) | Abdelghany, Osman (United Arab Emirates University) | Anin, Al (University of Oklahoma) | Rai, Chandra (University of Oklahoma) | Curtis, Mark (University of Oklahoma)
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.
Arman, Hasan (United Arab Emirates University) | Abdelghany, Osman (United Arab Emirates University) | El Tokhi, Mohamed (United Arab Emirates University) | Hashem, Waheed (United Arab Emirates University) | El Saiy, Ayman (United Arab Emirates University)
Basak, P.S. (Oil & Natural Gas Corporation Limited) | Deb, Abhijit (Oil & Natural Gas Corporation Limited) | Dotiwala, Sucheta (Oil & Natural Gas Corporation Limited) | Sanyal, A. (Oil & Natural Gas Corporation Limited) | Pokhriyal, S.K. (Oil & Natural Gas Corporation Limited)
Harilal, _ (Oil and Natural Gas Corporation Limited) | Rao, C.G. (Oil and Natural Gas Corporation Limited) | Saxena, R.C.P. (Oil and Natural Gas Corporation Limited) | Nangi, J.L. (Oil and Natural Gas Corporation Limited) | Sood, A. (Oil and Natural Gas Corporation Limited) | Gupta, S.K. (Oil and Natural Gas Corporation Limited)
The 3-D data of C-37 and adjoining prospects of Tapti-Daman sub-basin of Mumbai offshore Basin, India, have been evaluated for delineation and mapping of Mahuva pay sands. The pays were found over an anticlinal nosal feature in Upper Mahuva Unit of Lower Oligocene Mahuva Formation by one exploratory well in 1994. Conventional interpretation of 3-D data and subsequent drilling of wells towards up dip and down dip both could not map the areal extent of the pays. Post drill analysis of log and seismic data show that low impedance pay sands, embedded in high impedance shales, are separated in thin beds by limestone and/or shale streaks.
Delineation of these sands by conventional interpretation methods is difficult because of thin and discontinuous occurrences, high degree of vertical and lateral variability in net sand thickness, abundance of limestone streaks and limited bandwidth of seismic data. 3-D visualization of surfaces and volume attributes, neural network based seismic trace shape classification and spectral decomposition techniques have been applied with integration of well and log data. Amplitude attributes based on full bandwidth data were found more contaminated by thin limestone streaks. Spectral decomposition based iso-frequency sections and iso-frequency slices mapped areal extent and temporal thickness of pay zone. Voxel based 3-D visualization of selected frequencies from instantaneous frequency volumes and seismic trace shape classification maps provided comparable image of the reservoir sands. Marine sands near shore-zone areas during continued sea level fall are envisaged depositional system for the pay sands. The sandstones are spread over 90 km2 area in isolated sand bodies. The inferences are validated by drilled wells.