Summary Gas-condensate reservoirs differ from dry-gas reservoirs. The understanding of phase and fluid flow-behavior relationships is essential if we want to make accurate engineering computations for gas-condensate systems. Condensate dropout occurs in the reservoir as the pressure falls below the dewpoint, resulting in significant gas-phase production decreases. The goal of this study is to understand the multiphase-flow behavior in gas-condensate reservoirs and, in particular, to focus on estimating gas-condensate-well deliverability. Our new method analytically generates the inflow-performance-relationship (IPR) curves of gas-condensate wells by incorporating the effect of condensate banking as the pressure near the wellbore drops below the dewpoint. The only information needed to generate the IPR is the rock relative permeability data and a constant-composition-expansion (CCE) experiment. We have developed a concept of critical oil saturation near the wellbore by simulating both lean and rich condensate reservoirs and have observed that the loss in productivity caused by condensate accumulation can be closely tied to critical saturation. We are able to reasonably estimate re-evaporation of liquid accumulation by knowing the CCE data. We validated our new method by comparing our analytical results with fine-scale-radial-simulation-model results. We demonstrated that our analytical tool can predict the IPR curve as a function of reservoir pressure. We also developed a method for generating an IPR curve with field data and demonstrated its application with field data. The method is easy to use and can be implemented quickly. Another advantage of this method is that it does not require the knowledge of accurate production data including the varying condensate/gas ratio (CGR).
Developing tight sandstone across vast area requires proper data collection and analysis. Due to the tight nature and heterogeneity of these reservoirs, several vertical and horizontal wells need to be drilled and completed with multistage hydraulic fractures to assess their potential. Initial post-frac flowback tests, in addition to long-term pressure build-ups, have already been conducted on several of the wells. Data Analysis have assisted in characterization of the tight hydrocarbon reservoirs and evaluating of hydraulic fracture geometry. The results have aided to investigate the drainage radius and well interference, to determine the optimal frac and well spacing design. These information are highly needed to build and calibrate single and full field dynamic models to estimate and address the uncertainty on the ultimate recovery and to come up with an optimized development strategy of the field. The paper presents findings and key lessons learned to efficiently design pressure build-up tests in tight sandstone reservoirs.
Saudi Aramco is actively appraising the numerous unconventional shale and tight sand opportunities located across the kingdom of Saudi Arabia. The early phase of the unconventional gas program in the company has been directed towards exploration data gathering activities through drilling, coring, open-hole logging and completion of shale and tight sand gas resources. Due to the ultra-tight nature of these reservoirs, several vertical and horizontal wells have been drilled and completed with multistage hydraulic fractures to be able to produce them. Initial flow back tests, in addition to long term pressure build-up, have already been conducted on some of these wells, the analysis of which will help to characterize and better understand these tight hydrocarbon reservoirs. This paper discusses the results of pressure transient analyses and modelling performance of two unconventional tight sand wells. An Integrated workflow was developed for reservoir characterization and fluid flow modeling using well test analyses and a simulation tool designed specifically for unconventional reservoirs. Post fracture flowback data along with available petrophysical interpretation, geological and geophysical analyses and 3-D hydraulic fracture models were used to build and calibrate single well numerical models. For the purpose of comparison, two wells were selected: one from a dry gas reservoir, while the other was from a rich gas-condensate reservoir.
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