Heavy oil reservoirs pose distinctive pressure-analysis problems because high viscosity, low mobility, fluid-property nonlinearity, and pressure-dependent rock behavior distort the classical assumptions used in drawdown and buildup test interpretation. This article presents a publication-oriented review and analytical framework for interpreting pressure transient data from heavy oil reservoirs during flowing and shut-in periods. The study synthesizes recent work on pressure transient analysis, tight-oil physical constraints, threshold-pressure-gradient behavior, stress-sensitive permeability, thermal and solvent recovery implications, automated PTA, and integrated pressure-temperature workflows. It argues that heavy-oil well-test interpretation should be treated as a coupled fluid-rock-flow problem rather than as a conventional single-phase Darcy-flow exercise. The article shows how high viscosity delays radial-flow stabilization, increases wellbore-storage dominance, magnifies rate-control error, and can produce derivative signatures that mimic boundaries, skin, or composite reservoirs. It further explains how pressure-dependent viscosity, compressibility, porosity, and permeability affect mobility, storativity, superposition, Horner straight-line behavior, and type-curve matching. A practical workflow is proposed for data screening, diagnostic plotting, model selection, parameter estimation, and uncertainty communication. The article concludes that reliable heavy-oil pressure analysis requires early integration of PVT data, geomechanics, temperature data, rate history, and nonlinear numerical or semi-analytical models, especially when drawdown and buildup tests are used for field-development decisions.
Akpadu* et al. (Wed,) studied this question.
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