During reservoir development, asphaltene precipitation deposition triggers the blockage of seepage channels, significantly reducing the reservoir permeability and seriously affecting the effectiveness of water injection development and the operation efficiency of surface facilities. To alleviate this problem, this study proposes to use intermittent waterflooding (IWF) as an alternative strategy to improve reservoir dynamics by alternating periodic waterflooding and well shut-in operations. A synthetic reservoir model was developed based on the component simulator Eclipse 300, and the influence mechanisms of key parameters such as well shut-in time, injection rate, and injection start-up time were systematically investigated and compared and analyzed with the conventional water injection scheme. Numerical simulation results show that IWF can effectively suppress the amount of asphaltene deposition in the near-well zone. Early injection and higher injection rates can help maintain stable reservoir pressure and oil phase composition, thus limiting asphaltene precipitation. The study shows that optimizing the design of the intermittent water injection cycle helps improve the recovery rate and effectively reduces the risk of asphaltene formation damage, providing a practical water injection management strategy for high-risk reservoirs.

Asphaltene deposition remains a critical challenge in water-injected reservoirs, where pressure and compositional variations destabilize the oil phase, triggering precipitation and formation damage. This study explores the application of intermittent waterflooding (IWF) as a practical mitigation strategy, combining alternating injection and well shut-in times to stabilize fluid conditions. A synthetic reservoir model was developed in Eclipse 300 to evaluate how key parameters such as shut-in time, injection rate, and injection timing affect asphaltene behavior under varying operational regimes. Comparative simulations against traditional continuous waterflooding reveal that IWF can significantly suppress near-wellbore deposition, preserve permeability, and improve overall oil recovery. The results show that early injections and optimized cycling schedules maintain reservoir pressure above the bubble point, thereby reducing the extent of destabilization. This study offers a simulation-based framework for IWF design, providing insights into asphaltene control mechanisms and contributing to more efficient reservoir management in fields prone to flow assurance issues.

Bullheading is a well control technique where heavy kill fluid is pumped down a wellbore to force a gas influx back into the formation, but poor estimation of the required injection pressure has historically led to failed interventions, most notably during the Macondo/Deepwater Horizon blowout. This study numerically simulates bullheading operations in a deepwater reservoir setting using the Petrel E&P platform, focusing on bottomhole pressure (BHP) behavior and the injection pressure needed to displace an influx. A vertical-well grid model representative of deepwater turbidite reservoirs was built, and a sensitivity analysis was performed across five reservoir/operational parameters, namely horizontal permeability, vertical permeability, porosity, net-to-gross (NTG) ratio, rock compressibility, and injection rate, using thirty-nine simulation cases. Horizontal permeability and NTG ratio were found to have the greatest influence on injection pressure, followed by porosity and rock compressibility, while vertical permeability showed no measurable effect. Injection rate, the only field-controllable variable, showed a strong direct relationship with both BHP and injection pressure. A subsequent uncertainty and cluster analysis using horizontal permeability and NTG ratio identified representative low, mid, and high pressure scenarios. These results indicate that reservoir characterization, particularly of horizontal permeability and NTG is critical to accurately predicting injection pressure for safe bullheading design in deepwater wells, and that simulation outputs should be validated against downhole pressure gauge data to reduce estimation uncertainty.

This study investigates the impact of fracture conductivity on hydraulically fractured wells in the Eagle Ford Shale using commercial simulation software. Motivated by recent findings on conductivity degradation and the proven reliability of sensitivity analyses in shale reservoirs, a 17-stage horizontal well was modeled to evaluate productivity optimization. The methodology involved holding fracture fluid volume constant while analyzing conductivity variations across both single-fracture and full-well models. Production simulations were validated against real-time field data. Results indicate that the simulation models accurately represent the reservoir, with single-fracture scenarios yielding similar cumulative production and full-well models showing only minor deviations. Ultimately, the observed differences do not justify a significant deviation from current completion techniques under the modeling assumptions considered, as infinite-acting flow remains the dominant regime due to the reservoir’s low permeability.