Variations in Bounding and Scanning Relative Permeability Curves with Different Carbonate Rock Types
- Moustafa Dernaika (Ingrain Inc) | Mohammed Zubair Kalam (Abu Dhabi Co. Onshore Oil Opn.) | Ahmed Mohamed Dawoud (Abu Dhabi Co. Onshore Oil Opn.) | Mahmoud Ali Basioni (Abu Dhabi Co. Onshore Oil Opn.)
- Document ID
- Society of Petroleum Engineers
- Abu Dhabi International Petroleum Conference and Exhibition, 11-14 November , Abu Dhabi, UAE
- Publication Date
- Document Type
- Conference Paper
- 2012. Society of Petroleum Engineers
- 1.2.3 Rock properties, 5.2 Reservoir Fluid Dynamics, 1.6.9 Coring, Fishing, 5.1.5 Geologic Modeling, 1.14 Casing and Cementing, 5.5.2 Core Analysis, 5.8.7 Carbonate Reservoir, 5.5 Reservoir Simulation, 5.2.2 Fluid Modeling, Equations of State, 5.3.2 Multiphase Flow, 4.3.4 Scale, 5.1 Reservoir Characterisation, 1.1 Well Planning, 5.3.1 Flow in Porous Media, 5.4.1 Waterflooding, 5.2.1 Phase Behavior and PVT Measurements
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Relative permeability curves generally exhibit hysteresis between different saturation cycles. This hysteresis is mainly caused by wettability changes and fluid trapping. Different rock types may experience different hysteresis trends due to variations in pore geometry. Relative permeability curves may also be a function of the saturation height in the reservoir.
A detailed laboratory study was performed to investigate relative permeability behavior for a major carbonate hydrocarbon reservoir in the Middle East. Representative core samples covering five reservoir rock types (RRT) were selected based on whole core and plug X-ray CT, NMR T2, MICP, porosity, permeability and thin-section analyses. Primary drainage and imbibition water-oil relative permeability (bounding) curves were measured on all the five rock types by the steady state technique using live fluids at full reservoir conditions with in situ saturation monitoring. Imbibition relative permeability experiments were also conducted on the main RRT samples to assess the relative permeability (scanning) curves in the transition zone by varying connate water saturations.
Hysteresis effects were observed between primary drainage and imbibition cycles, and appeared to be influenced by the sample rock type involved (i.e. wettability and pore geometry). Variations in relative permeability within similar and different rock types were described and understood from local heterogeneities present in each individual sample. This was possible from dual energy CT scanning and high resolution imaging. Different imbibition trends from both oil and water phases were detected from the scanning curves which were explained by different pore level fluid flow scenarios. Relative permeability scanning curves to both oil and water phases increased with higher connate water. Relative permeability to oil was explained based on the occupancy of the oil phase at varying connate water saturations. The change in water relative permeability trend was addressed based on the connectivity of water at the varying connate water saturations. These results and interpretations introduced improved understanding of the hysteresis phenomena and fluid flow behavior in the transition zone of a cretaceous carbonate reservoir which can assist in the overall reservoir modeling and well planning.
Relative permeability (Kr) is among the most important petrophysical parameters used for reservoir engineering and management as it provides a great deal of information about the hydrodynamics of fluid flow in reservoir rocks. This saturation function can be used for estimating productivity, injectivity, hydrocarbons in place, breakthrough time, and ultimate recovery (Honarpour et al., 1986 and 1995; Heaviside, 1991).
Relative permeability is a function of saturation and saturation history. It depends on the direction of saturation changes as well as on the maximum and minimum achieved saturations (Masalmeh, 2001 and Jerauld and Salter, 1990). Hysteresis in relative permeability curves can exist between different saturation cycles. Masalmeh found that water relative permeability curves exhibited either very little or no hysteresis at all except when considerable part of the pore space became oil-wet. On the other hand, he found the oil relative permeability curves to show strong hysteresis between the primary drainage and primary imbibition curves for all wetting states, with very little hysteresis thereafter except for mixed to oil-wet plugs (Masalmeh, 2001). Actually, most experimental studies in literature have found that hysteresis is large for the nonwetting phase and either small or nonexistent for the wetting phase.
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