Scaling Laboratory-Data Surfactant-Imbibition Rates to the Field in Fractured-Shale Formations
- Dongmei Wang (University of North Dakota) | Jin Zhang (University of North Dakota) | Raymond Butler (University of North Dakota) | Kayode Olatunji (University of North Dakota)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- July 2016
- Document Type
- Journal Paper
- 440 - 449
- 2016.Society of Petroleum Engineers
- Scaling, Bakken Formation, Fracture, Imbibition rate, Spontaneours Imbibition
- 15 in the last 30 days
- 567 since 2007
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By use of existing methods, typical oil-recovery factors from the Bakken and other shale formations are low, typically less than 5% of original oil in place (OOIP). We are investigating the use of surfactant imbibition to enhance oil recovery from oil shale or other tight rocks. Much of our previous work has measured surfactant-imbibition rates and oil-recovery values in laboratory cores from the Bakken shale, Niobrara chalk/shale, and Eagle Ford formations. With optimized surfactant formulations at reservoir conditions, we observed oil-recovery values up to 20% of OOIP incremental over brine imbibition. However, whether surfactant imbibition will be a viable recovery process depends on achieving sufficiently high oil-production rates in a field setting. This, in turn, depends on three factors: the area of formation contact (through fractures and microfractures) when/where the surfactant formulation is introduced; the rates of surfactant imbibition; and the distances of surfactant imbibition into the rock and ultimate oil-displacement effectiveness. In this paper, we use analytical models to scale laboratory surfactant-imbibition rates to a field scale in fractured-shale formations.In laboratory cores, we observed imbibition rates that varied inversely with time. Dimensionless scaling groups were applied that compensate for the effects of sample size and shape, boundary conditions, permeability, porosity, and viscosity. Calculations were made of available fracture area, assuming typical horizontal well lengths and transverse-induced-fracture spacing in typical Bakken wells. These fracture areas were coupled with our imbibition-scaling groups to estimate oil-recovery rates in a field setting. Considering realistic timing, surfactant imbibition will generally not proceed more than a few meters into the low-permeability shale/chalk formations. These calculations indicate insufficient fracture area to provide a viable imbibition process if only the induced-fracture area is considered. However, recent results from geological, microseismic, and pressure-transient studies indicate considerably greater area associated with natural microfractures in our target formations. When the increased area suggested by the presence of microfractures is included in our analyses, the surfactant-imbibition process appears quite promising.
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