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Waterflooding in Carbonate Reservoirs: Does the Salinity Matter?
- Ahmed M. Shehata (Texas A&M University) | Mohammed B. Alotaibi (Texas A&M University) | Hisham A. Nasr-El-Din (Texas A&M University)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- August 2014
- Document Type
- Journal Paper
- 304 - 313
- 2014.Society of Petroleum Engineers
- 6.4 Primary and Enhanced Recovery Processes, 6.4.4 Reduction of Residual Oil Saturation, 6.3.1 Flow in Porous Media, 6.4.1 Waterflooding, 6.10.5 High Pressure-High Temperature (HPHT) Reservoirs, 6.10 Management of Challenging Reservoirs, 6 Reservoir Description and Dynamics, 6.10.1 Carbonate Reservoirs, 6.3 Fluid Dynamics
- EOR, coreflood, seawater, salinity, carbonate reservoirs
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Waterflooding has been used for decades as a secondary oil-recovery mode to support oil-reservoir pressure and to drive oil into producing wells. Recently, the tuning of the salinity of the injected water in sandstone reservoirs was used to enhance oil recovery at different injection modes. Several possible low-salinity-waterflooding mechanisms in sandstone formations were studied. Also, modified seawater was tested in chalk reservoirs as a tertiary recovery mode and consequently reduced the residual oil saturation (ROS). In carbonate formations, the effect of the ionic strength of the injected brine on oil recovery has remained questionable. In this paper, coreflood studies were conducted on Indiana limestone rock samples at 195°F. The main objective of this study was to investigate the impact of the salinity of the injected brine on the oil recovery during secondary and tertiary recovery modes. Various brines were tested including deionized water, shallow-aquifer water, seawater, and as diluted seawater. Also, ions (Na+, Ca2+, Mg2+, and SO2-4) were particularly excluded from seawater to determine their individual impact on fluid/rock interactions and hence on oil recovery. Oil recovery, pressure drop across the core, and core-effluent samples were analyzed for each coreflood experiment. The oil recovery using seawater, as in the secondary recovery mode, was, on the average, 50% of original oil in place (OOIP). A sudden change in the salinity of the injected brine from seawater in the secondary recovery mode to deionized water in the tertiary mode or vice versa had a significant effect on the oil-production performance. A solution of 20% diluted seawater did not reduce the ROS in the tertiary recovery mode after the injection of seawater as a secondary recovery mode for the Indiana limestone reservoir. On the other hand, 50% diluted seawater showed a slight change in the oil production after the injection of seawater and deionized water slugs. The Ca2+, Mg2+, and SO2-4 ions play a key role in oil mobilization in limestone rocks. Changing the ion composition of the injected brine between the different slugs of secondary and tertiary recovery modes showed a measurable increase in the oil production.
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