Pulsed Power Plasma Stimulation (3PS) represents a promising and environmentally favorable alternative to conventional well stimulation techniques for enhancing subsurface permeability. This comprehensive review tracks the evolution of plasma-based rock stimulation, offering insights from key laboratory, numerical, and field-scale studies. The review begins with foundational electrohydraulic discharge concepts and progresses through the evolution of Pulsed Arc Electrohydraulic Discharge (PAED) and the more advanced 3PS systems. High-voltage, ultrafast plasma discharges generate mechanical shockwaves and localized thermal effects that result in complex fracture networks, particularly in tight and crystalline formations. Compared to conventional well stimulation techniques, 3PS reduces water use, avoids chemical additives, and minimizes induced seismicity. Laboratory studies demonstrate significant improvements in permeability, porosity, and fracture intensity, while field trials show an increase in production from oil, gas, and geothermal wells. However, 3PS faces some limitations such as short stimulation radii and logistical constraints in wireline-based delivery systems. Emerging technologies like plasma-assisted drilling and hybrid PDC–plasma tools offer promising integration pathways. Overall, 3PS provides a practical, scalable, low-impact stimulation approach with broad applicability across energy sectors, especially in environmentally sensitive or water-scarce regions.

Hydraulic fracturing has enabled production from unconventional reservoirs in the U.S., but production rates often decline sharply, limiting recovery factors to under 10%. This study proposes an optimization workflow for the CO₂ huff-n-puff process for multistage-fractured horizontal wells in the Wolfcamp A formation in the Delaware Basin. The potential for enhanced oil recovery and CO₂ sequestration simultaneously was addressed using a coupled geomechanics–reservoir simulation. Geomechanical properties were derived from a 1D mechanical earth model and integrated into reservoir simulation to replicate hydraulic fracture geometries. The fracture model was validated using a robust production history matching. A fluid phase behavior analysis refined the equation of state, and 1D slim tube simulations determined a minimum miscibility pressure of 4300 psi for CO₂ injection. After the primary production phase, various CO₂ injection rates were tested from 1 to 25 MMSCFD/well, resulting in incremental oil recovery ranging from 6.3% to 69.3%. Different injection, soaking and production cycles were analyzed to determine the ideal operating condition. The optimal scenario improved cumulative oil recovery by 68.8% while keeping the highest CO₂ storage efficiency. The simulation approach proposed by this study provides a comprehensive and systematic workflow for evaluating and optimizing CO₂ huff-n-puff in hydraulically fractured wells, enhancing the recovery factor of unconventional reservoirs.

This study presents a comparative analysis of CO₂-EOR and water flooding scenarios to optimize oil recovery in a geologically heterogeneous reservoir with a dome structure and partial aquifer support. Using production data from twelve production and three monitoring wells, a dynamic reservoir model was built and successfully history-matched with a 1% deviation from actual field data. Three main recovery methods were evaluated: water flooding, continuous CO₂ injection, and water-alternating-gas (WAG) injection. Water flooding resulted in a four-fold increase from primary recovery, while continuous CO₂ injection provided up to 40% additional oil recovery compared to water flooding. WAG injection further increased recovery by 20% following water flooding. The minimum miscibility pressure (MMP) was determined using a 1D slim-tube simulation to ensure effective CO₂ performance. A sensitivity analysis on CO₂/WAG ratios (1:1, 2:1, 3:1) revealed that continuous CO₂ injection, particularly in high permeability zones, offered the most efficient recovery. An economic evaluation indicated that the optimal development strategy is 15 years of water flooding followed by 15 years of continuous CO₂ injection, resulting in a net present value (NPV) of USD 1 billion. This study highlights the benefits of CO₂-EOR for maximizing oil recovery and suggests further work on hybrid EOR techniques and carbon sequestration in depleted reservoirs.

This study evaluates the feasibility of CO₂ Water-Alternating-Gas (WAG) injection for enhanced oil recovery (EOR) in a highly heterogeneous reservoir using cost-effective and efficient tools. The Rule of Thumb method was initially used to screen the reservoir, confirming its suitability for CO₂-WAG injection. A fluid model was constructed by comparing several component lumping methods, selecting the approach with the least deviation from experimental data to ensure accuracy. The minimum miscibility pressure (MMP), a critical parameter for CO₂-EOR, was estimated using three methodologies: 1D simulation based on the slim tube test, semi-empirical analytical correlations, and fluid modeling. These techniques provided complementary insights into the reservoir’s miscibility conditions. The CO₂ Prophet software version 1 was employed to history-match production data and evaluate different development strategies. The Kinder Morgan CO₂ Scoping Model was used to perform production forecasting and assess the economic viability of implementing CO₂-WAG. Quantitative comparisons showed that the CO₂ Prophet version 1 model revealed minimal deviations from the history match results: oil production estimates differed by only 3.5%, and water production estimates differed by −4.11%. Cumulative oil recovery was projected to reach approximately 20.26 MMSTB over a 25-year production period. The results indicate that CO₂-WAG injection could enhance oil recovery significantly compared to water flooding while maintaining economic feasibility. This study demonstrates the practical integration of analytical tools and inexpensive models to evaluate and optimize CO₂-EOR strategies in complex reservoirs. The findings provide a systematic workflow for deploying CO₂-WAG in heterogeneous reservoirs, balancing technical and economic considerations.

This study examines the influence of activated carbon nanoparticle concentration and salinity on microwave heating efficiency for heavy oil extraction. By evaluating varying concentrations of activated carbon in sandstone cores, this research aims to determine the optimal balance that maximizes heating while avoiding pore blockages. Cores were injected with fracturing fluid containing 0.1% to 0.5% activated carbon and subjected to microwave heating. Results revealed that a 0.3% concentration achieved the highest average temperature without significant blockage, while higher concentrations led to blockages, impeding heat transfer. Salinity also played a role, with a 10% sodium chloride solution significantly enhancing heating efficiency, though further increases showed minimal impact. CT imaging confirmed that higher activated carbon concentrations resulted in particle accumulation near the injection side, causing uneven heat distribution. These findings highlight the importance of controlled nanoparticle concentration and salinity for optimizing thermal EOR, with 0.3% activated carbon identified as ideal for balancing heat efficiency and pore permeability. This study suggests that further refinement through advanced imaging like micro-CT scanning could enhance understanding of nanoparticle behavior, supporting more efficient thermal recovery techniques.

This study introduces nanoparticle-enhanced pulsed power plasma stimulation (NP-3PS) as a waterless fracturing technology for enhanced geothermal systems (EGS), employing ultrafast high-pressure plasma discharges from a 20 kJ capacitor charged to 40 kV to initiate and propagate complex fractures in 8-inch (20.32 cm) granite cubes via single pulses of 10, 12, and 16 kJ and a staged 4 + 6 kJ sequence. A 2-inch (5.03 cm) borehole was filled with nanofluid containing 0.3 wt % aluminum NP (60–80 nm) suspended in 7 wt % potassium chloride (KCl) + 0.18 wt % guar gum to sustain thermite reactions and multi-cycle shockwaves, generating peak pressures exceeding 100,000 psi (690 MPa) within microseconds. Post-stimulation diagnostics using 13 µm micro-CT, thin-section microscopy, and acoustic velocity analysis revealed dense branched fractures, porosity increase from 1.3% to 4.6% (~250%), and thermal conductivity reduction of 9–16%, indicating enhanced permeability and convective heat-transfer potential. The NP-driven multi-pulse mechanism reactivated existing fractures at lower energy without wire replacement, establishing a quantitative framework linking plasma dynamics, rock damage evolution, and thermal response, thus confirming NP-3PS as a scalable and sustainable alternative to hydraulic fracturing for geothermal reservoir stimulation.