Bridging the gap between laboratory-scale experiments and actual oilfield operations is a complex task that requires a compromise between real (authentic) fluids and model systems. Commercial products (i.e., asphaltene inhibitors and dispersants) are often designed to target a wide range of operating conditions and compositions of crude oils, which means that the performance becomes almost case-specific. Through Atomic Force Microscopy (AFM) imaging and Transmission/Backscattering signals (T/BS), the morphology of asphaltene deposits and the mechanisms that eventually lead to precipitated material were evaluated. Two different models (starting solutions) with four different n-alkanes were used to induce variability in asphaltene agglomeration and subsequent precipitation paths. It was found that increasing the carbon number shifted the observed precipitation detection time (T/BS data suggested a shift in the order of ~1000 s when comparing low and high carbon numbers) and influences the density of the precipitated material under static and a sufficiently high concentration of solvent conditions. Further analysis on the morphology of the resulting material after the addition of commonly used chemicals showed that asphaltene stability through inhibition (i.e., blockage or crowding of potential active sites) led to smaller complexes. One of the additives (PIBSA) reduced the average height in ~33% and the mean square roughness in ~72%. On the other hand, stability through dispersion (i.e., hindering agglomeration) leads to a polymer-like network bigger in size, noting that in both cases the system remains soluble. The use of APR resulted in an increase of ~41% and ~54% for the same parameters. This insight sheds light on how to devise efficient chemical strategies to prevent flow assurance issues.