Simulation Study on Surfactant-Polymer Flood Performance in Fractured Carbonate Reservoir
- Nawaf I. SayedAkram (Saudi Aramco) | Daulat Mamora (Texas A&M University)
- Document ID
- Society of Petroleum Engineers
- SPE/DGS Saudi Arabia Section Technical Symposium and Exhibition, 15-18 May, Al-Khobar, Saudi Arabia
- Publication Date
- Document Type
- Conference Paper
- 2011. Society of Petroleum Engineers
- 4.3.4 Scale, 5.2.1 Phase Behavior and PVT Measurements, 2.5.2 Fracturing Materials (Fluids, Proppant), 5.1 Reservoir Characterisation, 5.4.7 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex), 5.8.7 Carbonate Reservoir
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This paper presents a comprehensive simulation study on the impact of natural fractures on the performance of surfactant polymer flood in a field wide scale. The simulation model utilized for the study is a dual porosity dual permeability model representing 1/8 of a 20-acre 5-spot pattern. The model parameters studied include wettability alteration, interfacial-tension changes and mobility reduction effect. The results of this study clearly indicate the importance of reservoir description and fracture modeling for a successful surfactant-polymer flood. This may lead in huge difference in reserves booking from such EOR method.
Naturally fractured carbonate reservoirs are usually characterized by mixed wettablility and low matrix permeability which leads to low oil recovery and high remaining oil saturation. Enhanced oil recovery methods such as surfactant-polymer flood (SPF) enhance the recovery by increasing the spontaneous imbibitions either by lowering the interfacial tension or altering the wettability in the matrix. However, one of the main reasons for failed surfactant-polymer floods is under-estimating the importance of the reservoir and fluid characteristics especially the description of natural fractures and their effect on recovery.
Sensitivity runs were made in field size scale in order to compare oil recovery by capillary force, buoyancy force and viscous force. The simulation study indicates a relationship between water saturation and the start of altering wettability and/or interfacial tension to maximize oil recovery. Also, when a surfactant alters the rock wettability, an optimum IFT should be identified for faster and higher imbibitions. In addition, the study shows effect on recovery by permeability contrast between that of the fracture and that of the matrix as well as fracture orientation with respect to injector-producer direction.
About 40-60% of the original oil-in-place (OOIP) in reservoirs is left behind after secondary recovery. Over 60% of the remaining oil in the world can be found in carbonate reservoirs, which makes it a big area of interest for Enhance Oil Recovery (EOR) methods especially with the current oil price and increasing demand. Most of the carbonate reservoirs are fractured to a certain degree and either oil-wet or mixed-wet (Mohan, 2009).
The main characteristics of fractured reservoirs are the permeability enhancement provided by the fractures. In tight matrix blocks, fractures are the only means of fluid flow into a production well. However, the heterogeneity between fractures and matrix blocks can result in by-passed oil.
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