Search Results (201)

Temperature is a key factor in regulating interfacial behaviors and enhancing oil recovery during low-salinity water flooding in tight sandstone reservoirs. This study systematically investigates the synergistic mechanisms of temperature and salinity on ion exchange, wettability alteration, interfacial tension, and crude oil desorption. The experimental results show that elevated temperature significantly strengthens the oil–water–rock interactions induced by low-salinity water, thereby improving oil recovery. At 70 °C, the release of divalent cations such as Ca²⁺ and Mg²⁺ from the rock surface is notably enhanced. Simultaneously, the increase in interfacial electrostatic repulsion is evidenced by a shift in the rock–brine zeta potential from −3.14 mV to −6.26 mV. This promotes the desorption of polar components, such as asphaltenes, from the rock surface, leading to a significant change in wettability. The wettability alteration index increases to 0.4647, indicating a strong water-wet condition. Additionally, the reduction in oil–water interfacial zeta potential and the enhancement in interfacial viscoelasticity contribute to a further decrease in interfacial tension. Under conditions of 0.6 PW salinity and 70 °C, non-isothermal core flooding experiments demonstrate that rock–fluid interactions are the dominant mechanism responsible for enhanced oil recovery. By applying a staged injection strategy, where 0.6 PW is followed by 0.4 PW, the oil recovery reaches 34.89%, which is significantly higher than that achieved with high-salinity water flooding. This study provides critical mechanistic insights and optimized injection strategies for the development of high-temperature tight sandstone reservoirs using low-temperature waterflooding. Full article

The Baikouquan Oilfield edge expansion wells suffer from poor reservoir properties and limited connectivity, leading to low waterflooding sweep efficiency and insufficient reservoir energy. While oil displacement agents (ODAs) are currently employed in huff-and-puff flooding to enhance recovery, there is a lack of a solid basis for selecting these ODAs, and the dominant mechanisms of enhanced oil recovery (EOR) remain unclear. To address this issue, this study combines experimental work and reservoir numerical simulation to investigate the mechanisms of EOR by ODAs, optimize the selection of ODAs, and fine-tune the huff-and-puff flooding parameters. The results show that the selected nanoemulsion ODA (Nano ODA) significantly reduces the oil–water interfacial tension (IFT) by 97%, thereby increasing capillary number. Additionally, the ODA induces a shift from water–wet to neutral–wet conditions on rock surfaces, reducing capillary forces and weakening spontaneous imbibition. The Nano ODA demonstrates strong emulsification and oil-carrying ability, with an emulsification efficiency of 75%. Overall, the ODA increases the relative permeability of the oil phase, reduces residual oil saturation, and achieves a recovery improvement of more than 10% compared with conventional waterflooding. The injection volume and shut-in time were optimized for the target well, and the recovery enhancement from multiple cycles of huff-and-puff flooding was predicted. The research in this paper is expected to provide guidance for the design of huff-and-puff flooding schemes in low-permeability reservoirs. Full article

This paper demonstrates the comprehensive research of the target Middle Eastern carbonate oilfield on waterflooding technologies, including geological characteristics, integrated research, and principal development techniques. Geological research reveals that the Mishrif Formation in the B Oilfield is a gentle-sloping carbonate platform, with granular limestone serving as the primary reservoir rock and micrite limestone serving as the secondary reservoir rock. In addition, based on understandings drawn from geological characteristics and numerical simulation, the water flooding mode of IBPT, which can take full use of the gravity effect, has been proven to yield better sweep efficiency in the context of a thick and heterogeneous reservoir. Furthermore, a large-scale physical model experiment is designed to investigate the fluid migration between the producer and injector and indicates that the injected water migration is mainly divided into four phases, including a two-peak advance phase, a gravitational differentiation phase, a secondary bottom water phase, and a wellbore water coning phase. Subsequently, the principal techniques and corresponding optimized production responses of water flooding development are systematically illustrated, which consist of well type optimization, differentiated water injection strategies, injection pattern conversion, unstable water injection, selective well perforation, as well as tracer surveillance methodology. The outcomes of this study are directly derived from field performances and could provide concrete practical experiences for water flooding technology in the Middle East. Full article

Oil and gas reservoirs dominated by coarse clastic rocks, particularly conglomerates (including gravel sandstones), are commonly termed conglomerate reservoirs in both the domestic and international literature. Sandy conglomerate reservoirs generally have high thickness and high productivity per unit area, but because of their characteristics such as rapid lithology change, strong heterogeneity, low porosity, and low permeability, it is difficult to develop conventional waterflooding. There is an urgent need for an efficient development scheme for the giant sandy conglomerate reservoir. In this study, nuclear magnetic resonance (NMR) technology was employed to investigate the stratified injection-production strategy for large-scale sandy conglomerate reservoirs. Three representative cores from different strata were selected to perform CO₂ flooding and CO₂-water alternating gas (WAG) flooding experiments, respectively. The aim was to explore how different development methods affect the recovery efficiency of various core types and the distribution of remaining oil under miscible and immiscible pressure conditions. The results show that immiscible CO₂ flooding mainly displaces crude oil in large pores, and oil in micropores and mesopores is difficult to displace. After gas channeling, there is still a large area of residual oil “aggregate” in the core, and the recovery rate is low. Compared with medium-coarse sandstone, the strong heterogeneity of sandy conglomerates leads to early gas breakthrough and low recovery efficiency during gas flooding. Compared with CO₂ flooding, CO₂-WAG flooding can balance the micro-oil displacement effect between micropores and macropores, significantly improve the oil production in micropores and mesopores. Thus, CO₂-WAG flooding has a certain micropore “profile control” effect, which can delay the gas channeling and improve the core recovery efficiency of reservoirs, especially for the highly heterogeneous sandstone. Miscible CO₂ flooding can effectively extract the oil in the mesopores and micropores that immiscible CO₂ flooding is difficult to displace. The gas breakthrough is slower and the recovery is much higher in miscible CO₂-WAG flooding than that of immiscible one. Therefore, ensuring that the formation pressure is higher than the minimum miscible pressure to achieve miscible flooding is the key to reservoir stimulation. Full article

Meandering river point bar sand bodies, serving as critical reservoir units, exhibit significant lithofacies heterogeneity that governs remaining oil distribution patterns. Taking the Guantao Formation in the Gudao Oilfield as an example, this study integrates core observation, pore-throat structure characterization, and numerical simulation to reveal lithofacies characteristics of point bar sand bodies and their controlling mechanisms on incremental oil recovery distribution during surfactant–polymer (SP) flooding. The results demonstrate that point bar lithofacies display planar grain-size fining from concave to convex banks, with vertical upward-fining sequences (point bar medium sandstone facies → fine sandstone facies → siltstone facies). Physical property variations among lithofacies lead to remaining oil enrichment in relatively low-permeability portions of fine sandstone facies and low-permeability siltstone facies after waterflooding. SP flooding significantly enhances remaining oil mobilization through a “lithofacies-controlled percolation—chemical synergy” coupling mechanisms. The petrophysical heterogeneity formed by vertical lithofacies assemblages in the reservoir directly governs the targeted zones of chemical agent action (with interfacial tension reduction preferentially occurring in high-permeability lithofacies, while viscosity control dominates sweep enhancement in low-permeability lithofacies). This results in a distinct spatial differentiation of the incremental oil recovery, characterized by a spindle-shaped sweep improvement zone and a dam-type displacement efficiency enhancement zone. Full article

Cyclic solvent injection (CSI) with CO₂ is a promising non-thermal enhanced oil recovery (EOR) method for heavy oil reservoirs that also supports CO₂ sequestration. However, its effectiveness is limited by short foamy oil flow durations and low CO₂ utilization. This study explores how waterflooding and nanoparticle-assisted flooding can enhance CO₂-CSI performance through experimental and numerical approaches. Three sandpack experiments were conducted: (1) a baseline CO₂-CSI process, (2) a waterflood-assisted CSI process, and (3) a hybrid sequence integrating CSI, waterflooding, and nanoparticle flooding. The results show that waterflooding prior to CSI increased oil recovery from 30.9% to 38.9% under high-pressure conditions and from 26.9% to 28.8% under low pressure, while also extending production duration. When normalized to the oil saturation at the start of CSI, the Effective Recovery Index (ERI) increased significantly, confirming improved per-unit recovery efficiency, while nanoparticle flooding further contributed an additional 5.9% recovery by stabilizing CO₂ foam. The CO₂-CSI process achieved a maximum CO₂ sequestration rate of up to 5.8% per cycle, which exhibited a positive correlation with oil production. Numerical simulation achieved satisfactory history matching and captured key trends such as changes in relative permeability and gas saturation. Overall, the integrated CSI strategy achieved a total oil recovery factor of approximately 70% and improved CO₂ sequestration efficiency. This work demonstrates that combining waterflooding and nanoparticle injection with CO₂-CSI can enhance both oil recovery and CO₂ sequestration, offering a framework for optimizing low-carbon EOR processes. Full article

Low-salinity waterflooding (LSWF) enhances oil recovery at low cost in carbonate reservoirs, but its effectiveness requires the precise control of injected water chemistry and interaction with reservoir minerals. This study specifically investigates carbonated low-salinity waterflooding (CLSWF), where dissolved ${\mathrm{CO}}_2$ modulates geochemical processes. This study develops an integrated transport model coupling geochemical surface complexation modeling (SCM) with multiphase compositional dynamics to quantify wettability alteration during CLSWF. The framework combines PHREEQC-based equilibrium calculations of the Total Bond Product (TBP)—a wettability indicator derived from oil–calcite ionic bridging—with Corey-type relative permeability interpolation, resolved via COMSOL Multiphysics. Core flooding simulations, compared with experimental data from calcite systems at 100 ${}^{\circ }\mathrm{C}$ and 220 bar, reveal that magnesium ([${\mathrm{Mg}}^{2+}$]) and sulfate ([${\mathrm{SO}}_4^{2-}$]) concentrations modulate the TBP, reducing oil–rock adhesion under controlled low-salinity conditions. Parametric analysis demonstrates that acidic crude oils (TAN higher than 1 $\mathrm{m}$$\mathrm{g}$ KOH/$\mathrm{g}$) exhibit TBP values approximately $2.5 \mathrm{times}$ higher than those of sweet crudes, due to carboxylate–calcite bridging, while pH elevation (higher than 7.5) amplifies wettability shifts by promoting deprotonated ${\mathrm{-COO}}^{-}$ interactions. The model further identifies synergistic effects between ([${\mathrm{Mg}}^{2+}$]) (ranging from 50 to 200 mmol/kgw) and ([${\mathrm{SO}}_4^{2-}$]) (higher than 500 mmol/kgw), which reduce (${\mathrm{Ca}}^{2+}$)-mediated oil adhesion through competitive mineral surface binding. By correlating TBP with fractional flow dynamics, this framework could support the optimization of injection strategies in carbonate reservoirs, suggesting that ion-specific adjustments are more effective than bulk salinity reduction. Full article

Scale deposition during waterflooding, driven by the incompatibility between injected seawater and formation of water, poses significant challenges to reservoir performance. This study examines the mechanisms of inorganic scale formation and assesses its impact on productivity index, permeability, and pressure dynamics using the ECLIPSE simulator. A five-layered reservoir model with one injector and one producer (spaced 700 feet apart) was simulated under varying seawater injection rates of 1000, 3000, and 5000 stock tank barrels per day (stb/day). The results revealed rapid water breakthrough and escalating water cuts (34–38%) across scenarios, with scale deposition concentrated in layers 3 and 4, reducing permeability by up to 47% and productivity index by 50%. Layer 3 exhibited a threefold higher scaling due to the intense mixing of seawater and the formation of water. The study highlights the necessity of sulfate removal, alternative water sources, well repositioning, and preemptive scale inhibition to minimize reservoir damage caused by scale-induced permeability impairment. Full article

Waterflooding, a key method for secondary hydrocarbon recovery, has been employed since the early 20th century. Over time, the role of water chemistry and ions in recovery has been studied extensively. Low-salinity water (LSW) injection, a common technique since the 1930s, improves oil recovery by altering the wettability of reservoir rocks and reducing residual oil saturation. Recent developments emphasize the integration of LSW with various recovery methods such as CO₂ injections, surfactants, alkali, polymers, and nanoparticles (NPs). This article offers a comprehensive perspective on how LSW injection is combined with these enhanced oil recovery (EOR) techniques, with a focus on improving oil displacement and recovery efficiency. Surfactants enhance the effectiveness of LSW by lowering interfacial tension (IFT) and improving wettability, while ASP flooding helps reduce surfactant loss and promotes in situ soap formation. Polymer injections boost oil recovery by increasing fluid viscosity and improving sweep efficiency. Nevertheless, challenges such as fine migration and unstable flow persist, requiring additional optimization. The combination of LSW with nanoparticles has shown potential in modifying wettability, adjusting viscosity, and stabilizing emulsions through careful concentration management to prevent or reduce formation damage. Finally, building on discussions around the underlying mechanisms involved in improved oil recovery and the challenges associated with each approach, this article highlights their prospects for future research and field implementation. By combining LSW with advanced EOR techniques, the oil industry can improve recovery efficiency while addressing both environmental and operational challenges. Full article

This study establishes a covalently anchored wettability alteration strategy for enhanced oil recovery (EOR) using perfluorinated siloxane (CQ), addressing limitations of conventional modifiers reliant on unstable physical adsorption. Instead, CQ forms irreversible chemical bonds with rock surfaces via Si-O-Si linkages (verified by FT-IR/EDS), imparting durable amphiphobicity with water and oil contact angles of 135° and 116°, respectively. This modification exhibits exceptional stability: increasing salinity from 2536 to 10,659 mg/L reduced angles by only 6° (water) and 4° (oil), while 70 °C aging in aqueous/oleic phases preserved amphiphobicity without reversion—supported by >300 °C thermal decomposition in TGA; confirming chemical bonding durability. Mechanistic analysis identifies dual EOR pathways: amphiphobic surfaces lower rolling angles, surface free energy (SFE), and fluid adhesion to facilitate pore migration, while CQ intrinsically reduces oil-water interfacial tension (IFT). Core displacement experiments showed that injecting 0.05 wt% CQ followed by secondary waterflooding yielded an additional 10–18% increase in oil recovery. This improvement is attributed to enhanced mobilization of residual oil, with greater EOR efficacy observed in smaller pore throats. Field trials at the Huabei Oilfield validated practical applicability: Production rates of test wells C-9 and C-17 increased several-fold, accompanied by reduced water cuts. Integrating fundamental research, laboratory experiments, and field validation, this work systematically demonstrates a wettability-alteration-based EOR method and offers important technical insights for analogous reservoir development. Full article

As conventional waterflooding enters mid-to-late stages, chemical enhanced oil recovery (EOR) technologies such as polymer–surfactant binary flooding have emerged to address declining recovery rates. This study systematically investigates the synergistic effects of polymer–surfactant binary formulations through core-flooding experiments under varying concentrations, injection volumes, and salinity conditions. The optimal formulation, identified as 0.5% surfactant and 0.15% polymer, achieves a maximum incremental oil recovery of 42.19% with an interfacial tension (IFT) reduction to 0.007 mN/m. A 0.5 pore volume (PV) injection volume balances sweep efficiency and economic viability, while sequential slug design with surfactant concentration gradients demonstrates superior displacement efficacy compared with fixed-concentration injection. Salinity sensitivity analysis reveals that high total dissolved solids (TDS) significantly degrade viscosity, whereas low TDS leads to higher viscosity but only marginally enhances the recovery. These findings provide experimental evidence for optimizing polymer–surfactant flooding strategies in field applications, offering insights into balancing viscosity control, interfacial tension reduction, and operational feasibility. Full article

Upon reaching stabilized production in waterflooded reservoirs, waterflood performance curves are conventionally used to predict technically recoverable reserves (TRRs). However, as reservoirs enter high water-cut stages, the relationship between the relative permeability ratio and saturation becomes nonlinear, causing deflection in waterflood performance curves. This leads to systematic overestimation of both predicted TRR and ultimate recovery factors. To overcome these limitations in conventional TRR prediction methods, this study establishes a novel relative permeability ratio-saturation relationship based on characteristic relative permeability curve behaviors. The proposed model is validated for three distinct fluid-rock interaction types. We further develop a permeability-driven forecasting model for oil production rates and water cuts. Comparative analyses with a conventional waterflood curve methodology demonstrate significant accuracy improvements. The results show that while traditional methods predict TRR ranging from 78.40 to 92.29 million tons, our model yields 70.73 million tons—effectively resolving overestimation issues caused by curve deflection during high water-cut phases. This approach establishes a robust framework for determining critical development parameters, including economic field lifespan, strategy adjustments, and ultimate recovery factor. Full article

Vibration-stimulated waterflooding (VS-WF) is a promising enhanced oil recovery (EOR) method, especially for reservoirs with high-viscosity or emulsified oil. This study explores the effect of low-frequency vibration (2 Hz and 5 Hz) on oil mobilization under constant pressure and flow rate, using both crude and emulsified oil samples. Vibration significantly improves recovery by inducing stick-slip flow, lowering the threshold pressure, and enhancing oil phase permeability while suppressing the water phase flow. Crude oil recovery increased by up to 24% under optimal vibration conditions, while emulsified oil showed smaller gains due to higher viscosity. Intermittent vibration achieved similar recovery rates to continuous vibration, but with reduced energy use. Statistical analysis revealed a strong correlation between pressure fluctuations and oil production in vibration-assisted tests, but no such relationship in non-vibration cases. These results provide insight into the mechanisms behind vibration-enhanced recovery, supported by analysis of pressure and flow rate responses during waterflooding. Full article

This study addresses the unclear mechanisms by which preferential flow channels (PFCs), formed during long-term waterflooding, affect nano-gel microsphere (NGM) flooding efficiency, utilizing CMG reservoir numerical simulation software. A dynamic evolution model of PFCs was established by coupling CROCKTAB (stress–porosity hysteresis) and CROCKTABW (water saturation-driven permeability evolution), and the deep flooding mechanism of NGMs (based on their gel properties such as swelling, elastic deformation, and adsorption, and characterized by a “plugging-migration-replugging” process) was integrated. The results demonstrate that neglecting PFCs overestimates recovery by 8.7%, while NGMs reduce permeability by 33% (from 12 to 8 mD) in high-conductivity zones via “bridge-plug-filter cake” structures, diverting flow to low-permeability layers (+33% permeability, from 4.5 to 6 mD). Field application in a Chang 6 tight reservoir (permeability variation coefficient 0.82) confirms a >10-year effective period with 0.84% incremental recovery (from 7.31% to 8.15%) and favorable economics (ROI ≈ 10:1), providing a theoretical and engineering framework for gel-based conformance control in analogous reservoirs. Full article

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. Full article