Canadian oil sands represent a huge oil resource. Stable water-in-oil (W/O) emulsions, which persist in Athabasca oil sands from surface mining, are problematic, because of clay solids. This article focuses on the characterization of water-in-diluted-bitumen emulsions by nuclear magnetic resonance (NMR) measurement and the transient behavior of emulsions undergoing phase separation. An NMR restricted diffusion experiment (pulsed gradient spin−echo (PGSE)) can be used to measure the emulsion drop-size distribution. Experimental data from PGSE measurements show that the emulsion drop size does not change much with time, which suggests that the water-in-diluted-bitumen emulsion is very stable without an added coalescer. The sedimentation rate of emulsion and water droplet sedimentation velocity can be obtained from NMR one-dimensional (1-D) T 1 weighted profile measurement. Emulsion flocculation can be deduced by comparing the sedimentation velocity from experimental data with a modified Stokes' Law prediction. PR5 (a polyoxyethylene (EO)/polyoxypropylene (PO) alkylphenol formaldehyde resin) is an optimal coalescer at room temperature. For the sample without fine clay solids, complete separation can be obtained; for the sample with solids, a rag layer that contains solids and has intermediate density forms between the clean-oil and free-water layers. Once formed, this rag layer prevents further coalescence and water separation.

Processing of bitumen froth obtained from surface mining process of Athabasca oil sands yields stable water-indiluted bitumen emulsions. Even with a demulsifier, a "rag layer" forms between the oil and free water layers when clay solids are present. Experiments reveal that wettability of clay solids has a significant effect on emulsion stability. Kaolinite in tolueneÀbrine mixture was chosen as model system to study clay wettability alteration related to emulsion separation in bitumen froth treatment. Sodium naphthenate was added to simulate the presence of naphthenic acid in diluted bitumen. The fraction of the kaolinite that settled to the bottom of the aqueous phase was measured, and was referred to as "water-wet fraction", to characterize the wettability of kaolinite. Without any additives, 96% of the kaolinite was water-wet. Addition of only 100 ppm sodium naphthenate reduced the water-wet fraction to only 18%. Wettability of kaolinite was altered by pH control, silicate, and surfactant under different mechanisms. Addition of 366 ppm silicate at pH 10 resulted in 80% of kaolinite being water-wet. To prevent emulsion formation at high pH, cationic and amphoteric surfactants were evaluated as an alternative to alkali. Over 90% of kaolinite became water-wet when adding alkyl quaternary ammonium bromide, betaine, or amine oxide with optimal dosages.

Initial processing of bitumen froth obtained using a water-based extraction process from Athabasca oil sands yields stable water-in-bitumen emulsions. When the bitumen is diluted with naphtha to reduce its viscosity and density, almost complete separation can be obtained with a demulsifier in the absence of clay solids. However, a "rag layer" persists between the oil and free water layers when clay solids are present. Effects of the naphtha/bitumen (N/B) ratio, demulsifier selection, and silicate dosage on the rag layer formation and product quality have been studied. Emulsions with a N/B ratio of 0.7 are more stable than those with a N/B ratio of 4.0. This can be partially attributed to the difference in viscosity and density affecting the sedimentation velocity. The residual water and solid contents in the oil layer decrease with the addition of silicate. This behavior is attributed to the effect of silicate on clay wettability. Clay solids have toluene-soluble organic contents, which vary as follows: in the oil layer > in the rag layer > in the bottom layer. This result indicates that the solids are the most water-wet in the bottom (water) layer and the most oil-wet in the oil layer. In the same layer, samples with a N/B ratio of 0.7 have a higher toluene-soluble organic content in solids than those with a N/B ratio of 4.0. At 80 °C with a N/B ratio of 4.0, emulsion adding 200 ppm of demulsifier PR 6 and 4 Â 10 -4 M sodium m-silicate had 0.3-1.5% water and 0.9% solids in the oil layer, with the water content decreasing with an increasing height above the rag layer.

Initial processing of Athabasca oil sands obtained from the water-based extraction process yields stable water-in-bitumen emulsions. When the bitumen is diluted with naphtha to reduce its viscosity and density, partial separation can be obtained with a suitable demulsifier. However, a “rag layer” forms between the clean oil and free water layers. The partially oil-wet kaolinite in clay solids can retard water-in-oil emulsion coalescence, entrap oil drops, and form aggregates, which results in a rag layer in the middle of the sample. Once formed, this rag layer prevents further coalescence and water separation. We show here that wettability of kaolinite can be characterized via ζ potential measurement and modeling. A simplified Gouy−Stern−Grahame model and an oxide site binding model can be used to correlate the ζ potential of kaolinite in brine with different additives. Sodium silicate has the greatest effect per unit addition on changing the ζ potential of kaolinite and can be used to change the wettability of clay solids. The separation of water in diluted bitumen emulsion can be enhanced by changing the wettability of clay solids using silicate and pH control.

Production of oil from organic shale reservoirs is a function of porosity, hydrocarbon saturation, pore pressure, matrix permeability, and hydraulic fracture surface area plus fracture conductivity. Hydraulic fracture surface area, porosity, saturations and pore pressure dominate initial production rates. Matrix permeability becomes increasingly important in sustaining production later in time. Permeability measurements to oil from organic shale core samples are not commercially available today. However, permeability to oil is believed to be a function of pore throat size, wettability, and water saturation, the same as a conventional reservoir. This work investigates pore size, wettability, and expelled hydrocarbon volumes using log and core-based nuclear magnetic resonance data from the Eagle Ford Shale focused on the comprehensive evaluation of one well. Comparisons with core porosity measurements, scanning electron microscope images (SEM) and mercury injection capillary pressure tests (MICP) are compared with the nuclear magnetic resonance (NMR) interpretation for calibration and validation. The NMR T 2 distribution is partitioned into regions of bound and producible free fluid. Two types of pore systems are present in the Eagle Ford Shale; kerogen-hosted (OM) and inter/intra particle (IP). Bore hole logs indicate the upper Eagle Ford Shale is dominated by IP porosity, and the lower Eagle Ford Shale is dominated by OM porosity. Core NMR indicates OM pores are hydrocarbon wet while IP pores have mixed wettability. Core pore fluids are not representative of in-situ conditions as the lighter portion of the hydrocarbons have been expelled during core recovery. Comparison between log and core measured NMR allows the quantification of the expelled hydrocarbon-those zones with the "best" producibility. Understanding which portion of a shale reservoir contains producible fluids impacts target zone selection.