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Gas hydrates are ice-like solids that may form and aggregate in crude oil pipelines; in severe cases, the increase in frictional pressure drop may exceed the available driving force, resulting in a non-flowing (blockage) condition. To assess the severity of hydrate formation in oil- or condensate-dominant lines, a slurry viscosity model must be applied to and validated for hydrate-laden suspension. A well-known model, applied in industrial situations for hydrate slurry rheology, has been suggested to significantly underpredict apparent viscosity during the early and intermediate stages of hydrate blockage formation. Because hydrate particles suspended in the slurry may aggregate, this study interrogates their suspension rheology in two parts: The underlying suspension behavior was tested by injecting industrial anti-agglomerant (AA) chemicals, thereby identifying the contribution of particle aggregation for identical systems without AAs. A temperature-controlled high-pressure rheometer with a vane blade rotor was deployed, where hydrate-in-oil suspensions were formed from a metastable water-in-oil emulsion pressurized with methane. The results first illustrate that, at similar operating conditions, the addition of AAs reduced the hydrate growth rate by an order of magnitude and decreased the steady-state relative viscosity order of magnitude. After the hydrate volume fraction achieved a steady-state condition, the addition of AA suppressed the magnitude of the hydrate-in-oil slurry viscosity flow curve by an order of magnitude. Extrapolated to the infinite shear rate, the apparent viscosity behavior of hydrate-in-oil suspensions was compared to a range of rheological suspension models. The current industry model was indeed found to perform poorly, which may be due to assumptions of rigid and spherical particles; a revised suspension model considering arbitrarily shaped particles improved experimental predictions by between 50 and 60% for two crude oil systems.