Annual Technical Conference and Exhibition

Firenze, Italy

Annual Technical Conference and Exhibition

Firenze, Italy

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Ling Y.,Annual Technical Conference and Exhibition | Huang X.,Annual Technical Conference and Exhibition | Guo X.,Annual Technical Conference and Exhibition | Cai Y.,Annual Technical Conference and Exhibition
JPT, Journal of Petroleum Technology | Year: 2011

Integrated research on steam-assisted gravity-drainage (SAGD) production was carried out for an oil field in northeastern China by use of full-azimuth 3D seismics (cell size 6.25×6.25 m with a coverage area of 14 km2) and reservoir simulation on a well group [40 vertical wells and five horizontal wells in an area of 600×375 m (Fig. 1)]. The research indicated that the configuration of steam chambers caused by steam injection could be delineated from the high-resolution 3D-seismics results, and that this is more accurate than the reservoir-simulation model alone in the local-variation description of the chambers.


Minh C.C.,Annual Technical Conference and Exhibition | Sundararaman P.,Annual Technical Conference and Exhibition
SPE Journal | Year: 2011

We discuss the use of nuclear-magnetic-resonance (NMR) logging in the petrophysical evaluation of thin sand/shale laminations. NMR helps detect thin beds, determine fluid type, establish the hydrocarbon type and volume if hydrocarbon is present, and, finally, determine the permeability of the sand layers (as opposed to that of the sand/shale system). Experiments were conducted on samples of 100% sand, 100% clay, and sand/clay layers with an NMR-logging tool at surface to verify the characteristic T2 bimodal relaxation distribution often observed in NMR logs that are acquired in thin beds. From the bimodal distribution, it is often possible to determine a cutoff to separate the productive sand layers from the shale layers and, with it, the porosity fraction of each component. Subsequently, the sand fraction, or net/gross ratio, can be estimated assuming that the 100%-sand porosity is known. Because gas, oil, and water have different NMR properties, fluid-typing techniques such as 2D NMR offer useful insights into the fluid type and properties in thin-layer sands. Because the laminations thickness is often less than the antenna aperture, the estimated permeability of the sand/ shale system will undercall the true permeability of the sand layers only. In this case, their permeability can be estimated quickly from Darcy's fluid-flow model. We show examples of thin sand/shale laminations that are oilbearing and gas-bearing. In each case, the NMR detection was verified against borehole-imaging logs, and the fluid type in the sands was determined from multidimensional NMR analysis. The derived hydrocarbon volume was then compared with the results estimated from a triaxial induction tool. Permeability of the sand layers was also computed and compared to that of nearby thick sands. Core data in one well was used to validate NMR detection, porosity, permeability, and net sand thickness. Copyright © 2011 Society of Petroleum Engineers.

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