Laboratory Monitoring of Surfactant Imbibition Using Computerized Tomography

摘要

Oil production from fractured reservoirs can occur byspontaneous water imbibition and oil expulsion from thematrix into the fracture network. Injection of dilute surfactantcan recover additional oil by lowering water-oil interfacialtension (IFT) or altering rock wettability, thereby enhancingcountercurrent movement and accelerating gravitysegregation. Modeling of such recovery mechanisms requiresknowledge of temporal and spatial fluid distribution withinporous media. In this study, dilute surfactant imbibition testsperformed for vertically oriented carbonate cores of the Yatesfield were found to produce additional oil over brineimbibition. Computerized tomography (CT) scans wereacquired at times during the imbibition process to quantifyspatial fluid movement and saturation distribution, and CTresults were in reasonable agreement with material balanceinformation. Imbibition and CT-scan results suggest thatcapillary force and IFT gradient (Marangoni effect) expeditedcountercurrent movement in the radial direction within a shortperiod, whereas vertical gravity segregation was responsiblefor a late-time ultimate recovery. Wettability indices,determined by the U.S. Bureau of Mines centrifuge method,show that dilute surfactants have shifted the wettingcharacteristic of the Yates rocks toward less oil-wet. Anumerical model was developed to simulate the surfactantimbibition experiments. A good agreement between simulatedand experimental results was achieved with surfactantdiffusion and transitioning of relative permeability andcapillary pressure data as a function of IFT and surfactantadsorption. Single and multi-well pilot tests at Yates alsodemonstrated oil recovery improvement and water-oil-ratioreduction in response to dilute surfactant treatment.