Search Results (30)

Reservoirs in the Orinoco Heavy Oil Belt, Venezuela, typically hold natural foamy oil. Gas liberation during depletion leads to a sharp increase in viscosity, adversely impacting development efficiency. Therefore, this paper proposes a natural gas (CH₄)–chemical synergistic huff-and-puff method (CCHP). It utilizes the synergism between a stable foam plugging system and natural gas to supplement reservoir energy and promote the generation of secondary foamy oil. To evaluate the performance of 20 types of foam stabilizers (polymers and surfactants), elucidate the influence on production and properties of key parameters, and reveal the flow characteristics of produced fluids, 24 sets of foam performance evaluation tests were conducted using a high-temperature foam instrument. Moreover, 15 sets of core experiments with production fluid visualization were performed. The results demonstrate that, in terms of individual components, XTG and HPAM-20M demonstrated the best foam-stabilizing performance, achieving an initial foam volume of 280 mL and a foam half-life of 48 h. Conversely, the polymer–surfactant composite of XTG-CBM-DA elevated the initial foam volume to 330 mL while maintaining a comparable half-life, further enhancing the performance of foaming capacity for a stable foam system. For further application in the CCHP, oil production shows a positive correlation with both post-depletion pressure and chemical agent concentration; however, the foam gas–liquid ratio (GLR) exhibits an inflection point, with the optimal ratio found to be 1.2 m³/m³. During the huff-and-puff process, the density and viscosity of the produced oil decrease cycle by cycle, while resin and asphaltene content show a significant reduction. Furthermore, visualization results reveal that the foam becomes finer, more stable, and more uniformly distributed under precise parameter control, leading to enhanced foamy oil effects and improved plugging capacity. Moreover, the foam structure transitions from an oil-rich state to a homogeneous and stable configuration throughout the CCHP process. This study provides valuable insights for achieving stable and sustainable development in natural foamy oil reservoirs. Full article

Foam–CO₂ EOR Flooding is not very successful if unaccompanied by foam stabilizers such as nanoparticle fly ash (NFA). This study was conducted to determine the effect of NFA on foam stability by considering particle characteristics using the Bulk Foam Method as an additional condition. The test resulted in half-life times, which showed that in the absence of NFA, when oil was added, it was 211.5 s, and in salinity conditions, it was 232.5 s. This succeeds in improving half-life times to 226 s (with oil) and 241.5 s (with salinity) by adding NFA-Type F. For further research, conducting tests using reservoir conditions is recommended. Full article

Fractured vuggy reservoirs exhibit intricate fracture networks, where large fractures impose significant shielding effects on smaller ones, posing formidable challenges for efficient exploitation. A systematic evaluation of foaming volume, drainage half-life, decay behavior, and viscosity under varying temperatures and salinities was conducted for conventional foam, polymer-enhanced foam, and gel foam. The results yield the following conclusions: Compared to conventional foam, polymer-enhanced foam exhibits markedly improved stability. In contrast, gel foam, cross-linked with chemical agents, maintains stability for over one week at elevated temperatures, albeit at the expense of reduced foaming capacity. The three-dimensional network structure formed post-gelation enables gel foam to retain a thicker liquid film, exhibiting exceptional foam stability. As salinity increases, the base liquid viscosity of conventional foam remains largely unaffected, whereas polymer foam shows marked viscosity reduction. Gel foam displays a non-monotonic viscosity response—initially increasing due to ionic cross-linking and subsequently declining from excessive charge screening. All three systems exhibit significant viscosity decreases under high-temperature conditions. Visualized plate fracture model experiments revealed distinct flow patterns and mobility control performance; narrow fractures exacerbate bubble coalescence under shear stress, leading to enlarged bubble sizes and diminished plugging efficiency. Among the three systems, gel foam exhibited superior mobility control characteristics, with uniform bubble size distribution and enhanced stability. Integrating the findings from the foam mobility control experiments in parallel fracture systems with the diversion outcomes of mobility control and flooding, distinct performance trends emerge. It can be seen that the stronger the foam stability, the stronger the mobility control ability, and the easier it is to start the shielding effect. Combined with the stability of different foam systems, understanding the mobility control ability of a foam system is the key to increasing the sweep coefficient of a complex fracture network and improve oil-washing efficiency. Full article

Volume kinetics is a pharmacokinetic method for analysis of the distribution and elimination of infusion fluids. The approach has primarily been used to improve the planning of fluid therapy during surgery but is also useful for answering physiological questions. The kinetics is based on 15–35 serial measurements of the blood hemoglobin concentration during and after the fluid is administered intravenously. Crystalloid fluid, such as isotonic saline and Ringer’s lactate, distributes between three compartments that are filled in succession depending on how much fluid is administered. The equilibration of fluid between these three compartments is governed by five rate constants. The compartments are the plasma (V_c), and a fast-exchange (V_t1) and a slow-exchange interstitial compartment (V_t2). The last compartment operates like an overflow reservoir and, if filled, markedly, prolongs the half-life of the fluid. By contrast, the volume of a colloid fluid distributes in a single compartment (V_c) from where the expansion is reduced by capillary leakage and urinary excretion. This review gives 15 examples of physiological or medical questions where volume kinetics has provided answers. These include why urine flow is low during general anesthesia, the inhibitory effects of anesthetics on lymphatic pumping, the influence of dopamine and phenylephrine on urine output, fluid maldistribution in pre-eclampsia, plasma volume oscillations, and issues related to the endothelial glycocalyx layer. Full article

Nitrogen foam is a promising enhanced oil recovery (EOR) technique with significant potential for tertiary oil recovery. This improves the efficiency of the oil displacement during the gas drive processes while expanding the swept volume. However, in the high-temperature, high-salinity reservoirs of the Tahe Oilfield, conventional N₂ foam systems show suboptimal performance, as their effectiveness is heavily limited by temperature and salinity. Consequently, enhancing the foam stability under these harsh conditions is crucial for unlocking new opportunities for the development of Tahe fracture-vuggy reservoirs. In this study, the Waring–Blender method was used to prepare weathered coal particles as a foam stabilizer. Compared to conventional foam stabilizers, weathered coal particles were found to enhance the stability of the liquid film under high-temperature and high-salinity conditions. Firstly, the foaming properties of the six foaming agents were comprehensively evaluated and their foaming properties were observed at different concentrations. YL-3J with a mass concentration of 0.7% was selected. The foaming stabilization performance of four types of solid particles was evaluated and weathered coal solid particles with a mass concentration of 15% and particle size of 300 mesh were selected. Therefore, the particle-reinforced foam system was determined to consist of “foaming agent YL-3J (0.7%) + weathered coal (15.0%) + nitrogen”. This system exhibited a foaming volume of 310 mL at 150 °C and salinity of 210,000 mg/L, with a half-life of 1920 s. Finally, through interfacial tension and viscoelastic modulus tests, the synergistic mechanism between weathered coal particles and surfactants was demonstrated. The incorporation of weathered coal particles reduced the interfacial tension of the system. The formation of a skeleton at the foam interface increased the apparent viscosity and viscoelastic modulus, reduced the liquid drainage rate from the foam, and mitigated the disproportionation effect. These effects enhanced the temperature, salinity resistance, and stability of the foam. Consequently, they contributed to the stable flow of foam under high-temperature and high-salinity conditions in the reservoir, thereby improving the oil displacement efficiency of the system. Full article

Gas channeling treatment is a huge challenge for oil displacement and CO₂ sequestration in the practical CO₂ flooding process. The foaming agents can be used in the gas flooding process, which presents good application potential for gas channeling blockage. However, high temperature can affect surfactant foaming properties. This work takes a high-temperature heterogenous sandstone oil reservoir as an example; the foaming performance of different surfactants was evaluated via foamability, thermal stability, crude oil tolerance ability, and dynamic blocking capacity. The profile control performance of the optimized foaming agent was investigated via dual-core gas flooding experiments. (1) The results show that QPJ-c featured good foaming stability, which made it present the largest foam comprehensive index, although its foaming volume was slightly lower than that of QPJ-b. Its foaming volume retention rate was 83.2%, and its half-life retention rate remained 88.9% after 30 days aging at a temperature of 110 °C. (2) The foam resistance factor increased from 7 to 17 when the core permeability increased from 2 mD to 20 mD. This indicated that the high-permeability zone could be preferentially blocked by foam during the foam injection. (3) The dual-core flooding experiments verified that the fractional flow of the high-permeability core severely decreased due to the blockage of foam. The incremental oil recovery of the low-permeability core was 27.1% when the permeability ratio was 5. It increased to 40% when the permeability ratio was increased to 10. (4) Our work indicates that temperature-resistant CO₂ foam could be a good candidate for profile control during CO₂ flooding in the target reservoir. Full article

High-temperature steam injection is a primary method for viscosity reduction and recovery in heavy oil reservoirs. However, due to the high mobility of steam, channeling often occurs within the reservoir, leading to reduced thermal efficiency and challenges in enhancing oil production. Foam fluids, with their dual advantages of selective plugging and efficient oil displacement, are widely used in steam-injection heavy oil recovery. Nonetheless, conventional foams tend to destabilize under high-temperature conditions, resulting in poor stability and suboptimal plugging performance, which hampers the efficient development of heavy oil resources. To address these technical challenges, this study introduces a foam system reinforced with Janus nano-graphite, a high-temperature stabilizer characterized by its small particle size and thermal resistance. The foaming agents used in the system are sodium α-olefin sulfonate (AOS), an anionic surfactant, and octadecyl hydroxylpropyl sulfobetaine (OHSB), a zwitterionic surfactant. Under conditions of 250 °C and 5 MPa, the foam system achieved a half-life of 47.8 min, 3.4 times longer than conventional foams. Janus nano-graphite forms a multidimensional network structure in the liquid phase, increasing internal friction and enhancing shear viscosity by 1.2 to 1.8 times that of conventional foams. Furthermore, the foam gel system demonstrated effective steam-channeling control in heterogeneous heavy oil reservoirs, particularly in reservoirs with permeability differentials ranging from 3 to 9. These findings suggest that the Janus nano-graphite reinforced foam system holds significant potential for steam-channeling mitigation in heavy oil reservoirs. Full article

Dams are vital for irrigation, power generation, and domestic water needs, but siltation poses a significant challenge, especially in areas prone to water erosion, potentially shortening a dam’s lifespan. The Ahmed El Hansali Dam in Morocco faces heightened siltation due to its upstream region being susceptible to erosion-prone rocks and high runoff. This study estimates the siltation at the dam from its construction up to 2014 using bathymetric data and the Brown model, which is a widely-used empirical model that calculates reservoir trap efficiency. Additionally, the study evaluates the impact of Land Use and Land Cover (LULC) changes and projected future rainfall until around 2076 based on siltation rates. The results indicate that changes in LULC, particularly temporal variations in precipitation, have a significant impact on the siltation of the Ahmed El Hansali dam. Notably, rainfall is strongly correlated with the siltation rate, with an R² of 0.92. The efficiency of sediment trapping (TE) is 97.64%, meaning that 97.64% of the sediment in the catchment area is trapped or deposited at the bottom of the dam. The estimated annual specific sediment yield is about 32,345.79 tons/km²/yr, and the sediment accumulation rate is approximately 4.75 Mm³/yr. The dam’s half-life is estimated to be around 2076, but future precipitation projections may extend this timeframe due to the strong correlation between siltation and precipitation. Additionally, soil erosion driven by land management practices plays a crucial role in future siltation dynamics. Hence, this study offers a comprehensive assessment of the siltation dynamics at the Ahmed El Hansali dam, providing essential information on the long-term effects of erosion, land use changes, and climate projections. These findings may assist decision makers in managing dam reservoir sedimentation more effectively, ensuring the durability of the dam and extending the reservoir life. Full article

This study investigated the enhancing effects of the temperature-resistant polymer Poly(ethylene-co-N-methylbutenoyl carboxylate-co-styrenesulfonate-co-pyrrolidone) (hereinafter referred to as Z364) on the performance of cocamidopropyl hydroxy sulfobetaine (CHSB) foam under high-temperature and high-salinity conditions. The potential of this enhanced foam system for mobility control during heavy oil thermal recovery processes was also evaluated. Through a series of experiments, including foam stability tests, surface tension measurements, rheological assessments, and parallel core flooding experiments, we systematically analyzed the interaction between the Z364 polymer and CHSB surfactant on foam performance. The results indicated that the addition of Z364 significantly improved the strength, thermal resistance, and salt tolerance of CHSB foam. Furthermore, the adsorption of CHSB on the polymer chains enhanced the salt resistance of the polymer itself, particularly demonstrating stronger blocking effects in high-permeability cores. The experimental findings showed that Z364 increased the viscosity of the liquid film, slowed down liquid drainage, and reduced gas diffusion, effectively extending the half-life of CHSB foam and improving its stability under high-temperature conditions. Additionally, in parallel core flooding experiments, the polymer-enhanced foam exhibited significant flow diversion effects in both high-permeability and low-permeability cores, effectively directing more fluid into low-permeability channels and improving fluid distribution in heterogeneous reservoirs. Overall, Z364 polymer-enhanced CHSB foam demonstrated superior mobility control during heavy oil thermal recovery, offering new technical insights for improving the development efficiency of high-temperature, high-salinity reservoirs. Full article

The dilute-foam dispersion system improves oil recovery by reducing interfacial tension between oil and water, altering wettability, and diverting displaced fluids by plugging larger pores. An optimized foaming system is obtained by formability evaluation experiments, in which the half-life for drainage and foaming volume by different types and concentrations of surfactants are analyzed, followed by the addition of partially hydrolyzed polyacrylamide (HPAM) with varied concentrations to enhance the foam stability. Using COMSOL Multiphysics 5.6 software, the Jamin effect and plugging mechanism of the water–gas dispersion system in narrow pore throats were simulated. This dispersion system is applied to assist CO₂ huff-n-puff in a low-permeability core, combined with the online NMR method, to investigate its effects on enhanced oil recovery from the pore scale. Core-flooding experiments with double-pipe parallel cores are then performed to check the effect and mechanism of this dilute-foam dispersion system (DFDS) on enhanced oil recovery from the core scale. Results show that foam generated by combining 0.6% alpha-olefin sulfonate (AOS) foaming agent with 0.3% HPAM foam stabilizer exhibits the strongest foamability and the best foam stability. The recovery factor of the DFDS-assisted CO₂ huff-n-puff method is improved by 6.13% over CO₂ huff-n-puff, with smaller pores increased by 30.48%. After applying DFDS, the minimum pore radius for oil utilization is changed from 0.04 µm to 0.029 µm. The calculation method for the effective working distance of CO₂ huff-n-puff for core samples is proposed in this study, and it is increased from 1.7 cm to 2.05 cm for the 5 cm long core by applying DFDS. Double-pipe parallel core-flooding experiments show that this dispersion system can increase the total recovery factor by 17.4%. The DFDS effectively blocks high-permeability layers, adjusts the liquid intake profile, and improves recovery efficiency in heterogeneous reservoirs. Full article

Steam displacement is prone to cross-flow, small swept area, large oil–water ratio, large oil–water interfacial tension, and low oil displacement efficiency. Compared with steam flooding, foam flooding can effectively reduce the residual oil in the small throat of the main flow channel and the small hole in the near flow channel and increase the overall recovery factor. Therefore, researchers carried out CO₂ and chemical agent-assisted steam displacement. However, at present, there is a lack of research on the occurrence mechanism and model of residual oil. Steam flooding often encounters challenges such as cross-flow, limited sweep area, and high oil–water ratio. Foam flooding offers a promising alternative by effectively reducing residual oil in narrow throats and the near flow channel, thereby enhancing overall recovery rates compared to steam flooding alone. Therefore, chemical agent-assisted steam flooding was applied to enhance heavy oil recovery. However, the occurrence mechanism and model of residual oil after chemical agent-assisted steam is not clear. To fill this gap, the CO₂ foam viscosity reducer assisted steam (CFVAS) flooding technology has been adopted and carried out in several studies. First, the foam viscosity reducer was prepared and its foam properties (viscosity reduction effect, foam volume, and half-life) were tested. Subsequently, the CFVAS displacement experiments after steam flooding were carried out, and the flow behavior of the remaining oil in multiple regions (main flow channel, near flow channel, and far flow channel) was analyzed. Finally, the shape and number of remaining oil under different displacement stages were compared, and the occurrence mode of remaining oil under CFVAS displacement was determined. The results indicate the following: (1) During steam flooding, the amount of near flow channel residual oil decreased with injected pore volumes (PV), transforming into columnar structures in small perforations and film-like formations in far flow channels. (2) CFVAS flooding, including the foam stability mechanism, flow channel adjustment mechanism, and emulsification and dispersion mechanism, can improve overall recovery rates by 55.2% by driving the remaining oil in near flow channels. (3) During CFVAS flooding stage, crude oil mobility notably improved and flooding front expanded more evenly. Residual oil primarily existed as oil-in-water (O/W) emulsions with discontinuous columns. (4) In the CFVAS flooding stage, residual oil mainly formed O/W emulsions through emulsification and dispersion, with foam-filled large and medium pores, concentrating residual oil in thick and middle throats. This work can provide important references for injecting CO₂ gas into reservoirs to enhance heavy oil recovery and promote carbon sequestration. Full article

Carbon dioxide (CO₂) injection for enhanced oil recovery (EOR) has attracted great attention due to its potential to increase ultimate recovery from mature oil reservoirs. Despite the reported efficiency of CO₂ in enhancing oil recovery, the high mobility of CO₂ in porous media is one of the major issues faced during CO₂ EOR projects. Foam injection is a proven approach to overcome CO₂ mobility problems such as early gas breakthrough and low sweep efficiency. In this experimental study, we investigated the foam performance of a commercial anionic surfactant, alpha olefin sulfonate (AOS), in carbonate core samples for gas mobility control and oil recovery. Bulk foam screening tests demonstrated that varying surfactant concentrations above a threshold value had an insignificant effect on foam volume and half-life. Moreover, foam stability and capacity decreased with increasing temperature, while variations in salinity over the tested range had a negligible influence on foam properties. The pressure drop across a brine-saturated core sample increased with an increasing concentration of surfactant in the injected brine during foam flooding experiments. Co-injection of CO₂ and AOS solution at an optimum concentration and gas fractional flow enhanced oil recovery by 6–10% of the original oil in place (OOIP). Full article

In the process of unconventional oil and gas reservoir exploitation, it is difficult to reduce drilling fluid lost in natural fractures, enhance the CO₂ displacement effect and reduce foam drainage gas recovery costs. In most cases, foaming agents can solve these problems in a low-cost way in a short period of time. Foaming agent screening and evaluation is the key to this technology. However, there are few experimental tests used in the evaluation of foaming agent properties that match the actual unconventional oil or gas well conditions of high temperature and high pressure. Using the actual temperature and pressure conditions of a wellbore, the foaming capacity and half-life of two common foaming agents were systematically evaluated by using the high-temperature and high-pressure visual foam properties evaluation device (UPMX-500), in which the foaming agent’s volume concentration was 3‰ in a simulated formation water with a pH of 6 and salinity of 9 × 10⁴ mg/L. The high-temperature (40 °C, 60 °C, 80 °C, 100 °C) and high-pressure (0.1 MPa, 6.0 MPa, 8.0 MPa, 10.0 MPa) effect on the foaming capacity and half-life was analyzed. Binary linear regression of pressure and temperature was carried out, taking the foam composite index as the target and using a formula with high correlation. The results showed that the foam composite index (FCI) of the two foaming agents was positively correlated with pressure and temperature. The correlation of UT-7 was FCI = 64.1196T + 735.713p − 2066.2, the correlation of HY-3K was FCI = 62.5523T + 7220.391p − 2415.6, and the coefficients of determination were 0.9799 and 0.9895, respectively, with an error of less than 10%. This correlation equation can provide a reference for accurately predicting the foaming capacity of foaming agents under high-temperature and high-pressure conditions and can also be used to optimize foaming agents or to qualitatively evaluate results for the efficient exploitation of unconventional oil and gas reservoirs. Full article

Steam flooding is an effective development method for heavy oil reservoirs, and the steam flooding assisted by the profile control system can plug the dominant channels and further improve the recovery factor. High-temperature-resistant foam as a profile control system is a hot research topic, and the key lies in the optimal design of the foam system. In this paper, lignin was modified by sulfonation to obtain a high-temperature-resistant modified lignin named CRF; the foaming agent CX-5 was confirmed to have good high-temperature foaming ability by reducing the surface tension; the formula of the profile control system (A compound system of CRF and CX-5, abbreviated as PCS) and the best application parameters were optimized by the foam resistance factor. Finally, the effect of PCS-assisted steam flooding in enhanced oil recovery was evaluated by single sand packing tube flooding, three parallel tube flooding, and large-scale sand packing model flooding experiments. The results show that CX-5 has a good high-temperature foaming performance; the foam volume can reach more than 180 mL at 300 °C, and the half-life is more than 300 s. The optimal PCS formulation is 0.3 wt% CRF as an oil displacement agent + 0.5 wt% CX-5 as a foaming agent. The optimal gas–liquid ratio range is 1:2 to 2:1, and the high pressure and permeability are more conducive to the generation and stability of the foam. Compared with steam flooding, PCS-assisted steam flooding can improve oil recovery by 9% and 7.9% at 200 °C and 270 °C, respectively. PCS can effectively improve the heterogeneity of the reservoir, and increase the oil recovery of the three-parallel tube flooding experiment by 28.7%. Finally, the displacement results of the sand-packing model with large dimensions show that PCS can also expand the swept volume of the homogeneous model, but the effect is 9.46% worse than that of the heterogeneous model. Full article

There is a problem of a rapid decline in production caused by the repeated heating of the near-wellbore zone during steam stimulation. Finding a suitable foam system to expand the area of the steam chamber and slow down the rapid production of hot water during the recovery process can effectively improve the effect of steam stimulation. In this paper, CGS foam was prepared with high-temperature-resistant surfactant GD, graphite particles, and clay particles. Through the study of foam properties, it was found that with the addition of particles, the strength of the foam’s liquid film, half-life time, and temperature resistance was greatly improved. The appropriate permeability of the CGS foam and the movement characteristics of it in formations with different permeabilities were studied through a plugging experiment with a sand pack. The plugging performances of the GD foam, CGS foam, and pure particles in a simulated reservoir were compared. The development of the steam cavity during the steam stimulation process and the influence of injecting GD foam and CGS foam on the flow in the simulated reservoir were studied through a two-dimensional visualization model. The temperature resistance and stability of the CGS foam were better than those of GD foam in the simulated formation. Full article