Performing a reservoir simulation study for hydraulically fractured horizontal wells in unconventional reservoirs relies on input parameters which are not often well defined. The uncertainty of the input parameters (i.e. completion design, petrophysics, reservoir fluid phase) leads to uncertainty in the resulting history matches and less confidence when using the model results. This paper focuses on the importance of fluid phase characterization in reservoir simulation studies.
One of the challenges the industry currently faces is PVT (pressure-volume-temperature) fluid characterization for tight rock formations. When submitting a production fluid sample for analysis, it is crucial to define an accurate estimate of pressure, temperature, and gas-oil ratio (GOR) in order to place the sample in the appropriate fluid window to yield a representative PVT characterization for use in reservoir simulation studies.
The case study presented in this paper describes a reservoir simulation study in the Powder River Basin with varying fluid regimes across the field (Figure 1). This particular field has three different fluid systems driven by differences in basement heat flow: black oil, volatile oil, and gas condensate. Two different reservoir simulation studies within the same field will be described in this paper. The first reservoir simulation study was developed on an unbounded well in an area of the field interpreted as black oil. The second reservoir simulation study focused on a three well pad in an area interpreted to be gas condensate. Both simulation studies had accompanying PVT reports; unfortunately, irregular early production led to uncertainty in the recombination GOR and the resulting PVT characterizations. Despite modifying several modeling parameters, the model did not respond as expected and a representative history match was difficult to achieve. By re-evaluating the fluid window and PVT conditions, the history match for wells in both studies improved substantially.