Optimal upscaling of a high-resolution static geologic model that reflects the flow performance of the reservoir is important for reasons such as time and calculation efficiency. In this study, we demonstrate that honoring reservoir heterogeneity is critical in predicting accurate production and reducing the time and cost of running reservoir flow simulations for the Hunton Group carbonate. We integrated three-dimensional (3D) seismic data, well logs, thin sections, outcrops, multiscale fracture studies, discrete fracture networks, and geostatistical methods to create a 100 × 150 × 1 ft gridded representative geologic model. We calibrated our gridded porosity and permeability parameters, including the evaluation of fractures, by history matching the simulated production rate and cumulative production volumes from a baseline fine-scale model generated from petrophysical and production data obtained from five wells. We subsequently reperformed the simulations using a suite of coarser grids to validate our property upscaling workflow. Compared to our baseline history matching, increasing the horizontal grid cell sizes (i.e., horizontal upscaling) by factors of 2, 4, 8, and 16 results in cumulative production errors ranging from +0.5% for two time (2×) coarser to +74.22% for 16× coarser. The errors associated with vertical upscaling were significantly less, i.e., ranging from +0.5% for 2× coarser to +10.8% for 16× coarser. We observed higher production history matching errors associated with natural fracture size. Results indicate that greater connectivity provided by natural fracture length has a larger effect on production compared to the higher permeability provided by larger apertures. We also estimated the trade-off between accuracy and run times using two methods: (a) using progressively larger grid cell sizes; (b) applying 1, 5, 10, and 20 parallel processes. Computation time reduction in both scenarios may be described by simple power law equations. Observations made from our case study and upscaling workflow may be applicable to other carbonate reservoirs.

The problem of condensate blocking in low permeability gas-condensate reservoirs is greatly affected by the rock-fluid interactions and capillary trapping. Many publications suggest wettability alteration to gas-wetting as a permanent solution to the problem. In this work, we present a simulation study on the optimum wettability conditions for maximum gas-condensate well productivity enhancement. Most of the work in this area focuses on reversal of wetting conditions from liquid-wetting (contact angle of 0 degree) to gas-wetting (with contact angle around 150 degrees). On the experimental side, chemicals are tested in its ability to change wettability. On the simulation side, research shows that changing the wettability to gas-wetting in the near wellbore region results in better productivity than the original liquid-wetting state. Our work investigates various states of wettability ranging from liquid-wetting to gas-wetting and its effect on gas-condensate well productivity. We also study the effect of reservoir permeability, reservoir pressure and treatment radius on the well productivity enhancement by wettability alteration.

In gas condensate reservoirs, deliverability starts to decrease when retrograde condensation occurs. As the bottom-hole pressure drops below the dew-point, gas condensate and water build-up impede flow of gas to the wellbore. In order to stop the reduction in productivity, many publications suggest wettability alteration to gas-wetting as a permanent solution to the problem. Previous simulation work suggests an "optimum wetting state" to exist where maximum gas condensate well productivity is reached. This work has direct application in gas-condensate reservoirs, especially in identifying the most effective stimulation treatment which can be designed to provide the optimum wetting conditions in the near-wellbore region. In this work, we aim to show the existence of such an optimum state of wettability that result in maximum gas mobility and in an increase of the relative permeability curves. We present an experimental study on Berea sandstone rocks treated with a fluorinated polymer and investigate the optimum fluorinated polymer concentration that would alter the wettability to intermediate gas-wet. Different experimental techniquesincluding flow tests and spontaneous imbibition are conducted to examine the effect of treatments on wettability. Interaction between rocks and the fluids is studied using a MicroCT scanner. The studies in this area are important to improve the productivity of gas condensate reservoirs where liquid accumulates, decreasing production of the well. Efficiency in the extraction of natural gas is important for the economic and environmental considerations of the oil and gas industry. Wettability alteration is one of the newest stimulation methods proposed by researchers, and shows great potential for future field applications and further research studies.