Modeling and Forecasting Enhanced Condensate Recovery from Rich Gas-Condensate Regions in Eagle Ford

Abstract

Abstract The development of unconventional reservoirs is strongly affected by the reliability of the production forecast and project economics. This paper has addressed these issues by analyzing the performance of several wells using both analytical and numerical modeling. For instance, after history matching a portion of each well's production history, we forecasted the remaining portion of the well's production history using the early history-matched model parameters. Next, using mathematical models, we studied the feasibility of Enhanced Condensate Recovery (ECR) to increase condensate production and to utilize and store CO2. This research study includes multi-phase rate transient analyses of five wells and a pressure build-up test on one of the wells to calculate the stimulated permeability of the SRV region. Moreover, decline curve analysis of 34 wells in four well-groups (based on their landing zones) indicated that the wells in three landing zones had similar ‘Oil EUR’ while wells landed in the region between Austin Chalk and Eagle Ford had the highest ‘Gas EUR’. Our Eagle Ford compositional reservoir model consisted of three horizontal wells in the liquid-rich volatile oil region. After matching the production history of the wells, our model correctly forecasted the future performance of the wells. Furthermore, the input permeability of the SRV region in the history match was two orders of magnitude higher than the core permeability—confirming permeability enhancement resulting from hydraulic fracturing. The history-matched compositional reservoir model was used to study cyclic (Huff-n-Puff) CO2, lean wet gas, and dry gas ECR to evaluate the potential of improved condensate recovery. Each of the three injected compositions indicated considerable enhanced condensate recovery (ECR). The enhanced condensate variability was further studied by changing cycle length, injection rate and injection pressure. The optimum CO2 enhanced condensate recovery was obtained by injecting CO2 for 60 days followed by 180 days of production. The incremental condensate production after 4 cycles increased by 19% above the primary production with a net CO2 utilization of 8550 scf per bbl of incremental condensate.