Sand Pack Flooding Experiments Research Articles

Theoretical and experimental investigation of the impact of oil functional groups on the performance of smart water in clay-rich sandstones

This research investigated the effect of ion concentration on the performance of low salinity water under different conditions. First, the effect of injection water composition on interparticle forces in quartz-kaolinite, kaolinite-kaolinite, and quartz-oil complexes was tested and modeled. The study used two oil samples, one with a high total acid number (TAN) and the other with a low TAN. The results illustrated that reducing the concentration of divalent ions to 10 mM resulted in the electric double layer (EDL) around the clay and quartz particles and the high TAN oil droplets, expanding and intensifying the repulsive forces. Next, the study investigated the effect of injection water composition and formation oil type on wettability and oil/water interfacial tension (IFT). The results were consistent with the modeling of interparticle forces. Reducing the divalent cation concentration to 10 mM led to IFT reduction and wettability alteration in high TAN oil, but low TAN oil reacted less to this change, with the contact angle and IFT remaining almost constant. Sandpack flooding experiments demonstrated that reducing the concentration of divalent cations incremented the recovery factor (RF) in the presence of high TAN oil. However, the RF increment was minimal for the low TAN oil sample. Finally, different low salinity water scenarios were injected into sandpacks containing migrating fines. By comparing the results of high TAN oil and low TAN oil samples, the study observed that fine migration was more effective than wettability alteration and IFT reduction mechanisms for increasing the RF of sandstone reservoirs.

Flow Behavior and Mechanism Insights into Nanoparticle-Surfactant-Stabilized Nitrogen Foam for Enhanced Oil Recovery in the Mature Waterflooding Reservoir.

To solve the problem of poor stability and low enhanced oil recovery efficiency of conventional foam, nanoparticle-surfactant-stabilized nitrogen foam was prepared, and the influence of temperature, salinity, oil content, and pressure on foam performance was systematically investigated. Then, the flow behavior of conventional foam and nanoparticle-surfactant-stabilized foam in porous media was studied. Parallel sand pack flooding and visualization microflooding experiments were performed to investigate the enhanced oil recovery ability of nanoparticle-surfactant-stabilized foam from core-scale to pore-scale. Results showed that the nanoparticles can improve foam performance. When the temperature increases from 60 to 100 °C, the foam volume and foam half-life of nanoparticle-surfactant-stabilized foam decrease by 20 and 36%, respectively. The nanoparticle-surfactant-stabilized foam has a good salt resistance. The oil content limit value of the foam performance is 15%. With the increase of pressure, the foaming performance and foam stability are enhanced obviously. Compared with conventional surfactant-stabilized foam, the nanoparticle-surfactant-stabilized foam can have better plugging and expansion of the swept volume capacity. The micromodel flooding results are consistent with the parallel sand pack flooding results. Compared with conventional surfactant stabilized foam, nanoparticle-surfactant-stabilized foam has better enhanced oil recovery ability than conventional surfactant-stabilized foam due to its higher foaming ability, foam stability, and sweep efficiency improvement ability.

Enhanced oil recovery and mitigating challenges in sandstone oil reservoirs employing EDTA chelating agent/ seawater flooding

While low salinity water (LSW) holds promise for improving oil recovery, its implementation is comparatively costly due to the substantial volumes of fresh water required to dilute seawater (SW). Additionally, concerns arise regarding potential issues related to LSW, including fines migration in sandstone reservoirs and scale formation in carbonate reservoirs. Chelating agents can be introduced into undiluted SW to bind with metal ions, thereby lowering its salinity. This approach mimics the behavior of LSW injection while overcoming associated challenges. This study involves measuring oil/injected solution interfacial tension (IFT), evaluating sandstone surface wettability alteration, along with conducting different sand pack flooding scenarios using Ethylenediaminetetraacetic acid (EDTA) chelating agent. The aim was to comprehend the EDTA oil recovery mechanisms and determine the optimal concentration of EDTA that minimizes chemical consumption while maximizing oil recovery. The findings indicated that incorporating 5 wt% EDTA into SW significantly reduced IFT from 29.52 mN/m to 4.75 mN/m, making the oil nearly miscible in the solution. Moreover, wettability tests confirmed that a minimum EDTA concentration of 5 wt% is required to shift wettability from oil-wet to strongly water-wet conditions. Sand pack flooding experiments, on the other hand, further demonstrated that this optimized fluid system can potentially recover an additional 16.1 % of oil following SW flooding. Finally, inductively coupled plasma (ICP) analysis revealed a notable increase in metal ion concentration during EDTA flooding, indicating enhanced leaching of metals from the sandstone surface and improved wettability characteristics.

Production Optimization of Heavy Oil Recovery Utilizing Mo-Ni Based Liquid Catalysts: A Simulation Approach

In recent years, the demand for heavy oil has increased due to its abundant availability and low cost. However, the extraction of heavy oil poses a significant challenge due to its high viscosity and low mobility. Therefore, various methods have been developed to enhance the recovery of heavy oil, including the use of catalysts. This study has created a unique simulation approach that uses liquid catalysts (LCs) to improve heavy oil recovery. In this work, laboratory testing dataset and numerical simulation studies were used to examine the potential of applying LCs as an alternative chemical agent for enhancing heavy oil recovery. CMG-STARS and CMOST modules were used to historical match the laboratory scale results of two sand-pack flooding experiments (water flooding and liquid catalyst flooding in tertiary recovery mode). Moreover, a sensitivity study was conducted to apply a wide range of assumptions to determine the most effective process controlling parameters. Finally, oil production optimization is performed using a genetic algorithm (particle swarm optimization) by selecting the optimum-operating parameters. In comparison to typical water flooding, the results revealed a discernible rise in the heavy oil recovery factor (RF) when injecting LCs. The simulation results showed that the optimized production strategy could increase the ultimate oil recovery by up to 45.06%. The injection rate, slug size, and injection temperature were found to be significant factors in optimizing the production of heavy oil. This simulation approach can be used to optimize the production of heavy oil using acidic Mo-Ni based liquid catalyst in different reservoirs.

Insights into the Injectivity and Propagation Behavior of Preformed Particle Gel (PPG) in a Low-Medium-Permeability Reservoir.

Heterogeneous phase combined flooding (HPCF) has been a promising technology used for enhancing oil recovery in heterogeneous mature reservoirs. However, the injectivity and propagation behavior of preformed particle gel (PPG) in low-medium-permeability reservoir porous media is crucial for HPCF treatment in a low-medium-permeability reservoir. Thus, the injectivity and propagation behavior of preformed particle gel in a low-medium-permeability reservoir were systematically studied by conducting a series of sand pack flooding experiments. The matching factor (δ) was defined as the ratio of the average size of PPG particles to the mean size of pore throats and the pressure difference ratio (β) was proposed to characterize the injectivity and propagation ability of PPG. The results show that with the increase in particle size and the decrease in permeability, the resistance factor and residual resistance factor increase. With the increase in the matching factor, the resistance factor and residual resistance factor increase. The higher the resistance factor and residual resistance factor are, the worse the injectivity of particles is. By fitting the relationship curve, PPG injection and propagation standards were established: when the matching coefficient is less than 55 and β is less than 3.4, PPG can be injected; when the matching coefficient is 55-72 and β is 3.4-6.5, PPG injection is difficult; when the matching coefficient is greater than 72 and β is greater than 6.5, PPG cannot be injected Thus, the matching relationship between PPG particle size and reservoir permeability was obtained. This research will provide theoretical support for further EOR research and field application of heterogeneous phase combined flooding.

Synergistic collaborations between surfactant and polymer for in-situ emulsification and mobility control to enhance heavy oil recovery

Surfactant-polymer (SP) combined systems is an effective nonthermal method to enhance the heavy oil recovery, through in-situ emulsification and mobility control mechanisms. In this study, a novel SP system was developed using 0.2 wt% anionic surfactant (alkyl naphthol polyoxyethylene ether sulfonate, ANES) and 0.1 wt% polymer (partially hydrolyzed polyacrylamide, HPAM). The SP system had viscosity reduction rate of ∼ 98 %, viscosity ratio of oil to displaced water (μo/μd) of ∼ 3.95 and IFT of ∼ 0.29 mN/m, beneficial for decreasing the mobility ratio of water to heavy oil. Then, the applied performances including emulsion morphologies and stability, wettability alteration ability were systematically characterized. The results showed that the freshly O/W emulsions formed by SP system displayed uniform droplet size distribution, as well as high stability with tight interfacial film. In addition, the SP system exhibited excellent wettability alteration property with low contact angle of 18.3°. The synergistic collaboration mechanisms of surfactant and polymer include heavy oil–water interfacial tension reduction, in-situ emulsification, oil-viscosity reduction and water-viscosity increase. Finally, the static oil washing and dynamic sand-pack flooding experiments showed that the SP system exhibited high oil washing efficiency (62.89 %) and enhanced oil recovery efficiency (56.9 %) with improving the mobility controllability after the primary water-flooding process. This study indicated that the synergistic collaborations between surfactant and polymer had great potential to enhance the heavy oil recovery.

Influence of viscosity ratio on enhanced oil recovery performance of anti-hydrolyzed polymer for high-temperature and high-salinity reservoir

The viscosity ratio of polymer and oil is a crucial factor for polymer flooding, which can affect the water–oil mobility ratio and oil recovery. However, for high-temperature and high-salinity reservoirs, the reasonable viscosity ratio limit of polymer flooding under the condition of medium–high permeability and low oil viscosity is not clear. Thus, the heterogeneous sand-pack flooding experiments were carried out to analyze the influence of polymer–oil viscosity ratio on the enhanced oil recovery (EOR) performance of anti-hydrolyzed polymer to establish a reasonable viscosity ratio limit. Then the three-dimensional heterogeneous model flooding experiments were performed to clarify the mechanism. The results showed that when the permeability ratio was the same, as the viscosity ratio increased from 0.15 to 2.0, the incremental oil recovery increased from 3.2% to 27.2%. When the viscosity ratio was the same, the incremental oil recovery decreased with the increase in the permeability ratio. The reasonable viscosity ratio ranges from 1.0 to 1.5. For three-dimensional heterogeneous model flooding experiments, as the polymer–oil viscosity ratio increased from 0.45 to 1.0, the swept area of high and low permeability area was expanded and the oil saturation near the injection well in the mainstream channel was greatly reduced. Moreover, when the polymer–oil viscosity ratio was 1, the difference in the width of the mainstream channels between high and low permeability layers in the saturation field decreased, and the degree of utilization in low permeability layers increased significantly. As the polymer–oil viscosity ratio increased from 0.45 to 1.0, the incremental oil recovery increased from 16.2% to 24%.

A study on the mitigation of formation damage caused by excessive silica-based gel application in water shut-off treatments

This study investigated the mitigation of formation damage caused by silica-based gels. The historical development of water shut-off treatments in the oil and gas industry was also discussed in the paper. The authors highlighted the importance of silicate methods in reservoir conformance control and enhanced oil recovery. They also discussed the recent resurgence of interest in silicates due to their eco-friendly properties and potential for high-temperature applications. Weight loss experiments and sandpack flooding experiments were conducted to assess the removal efficiency of blocking under reservoir conditions. The results showed that a 1% NaOH-containing aqueous solution can completely dissolve the bulk gel within a relatively short timeframe. İt is noteworthy that 10-12 hours is typically sufficient to eliminate the gel responsible for formation damage in the bulk phase. In sandpack flooding experiments, it was found that NaOH injection can effectively remove gel blockages, but it may require multiple injections to achieve complete removal. Overall, this study provides a comprehensive overview of the mitigation of formation damage caused by silica-based gels. The results of this study can be used to improve the design and implementation of gel-based water shut-off treatments in the oil and gas industry. Keywords: silica gel; water shut-off; formation damage; sandpack; gel block.

A comprehensive evaluation of the effect of key parameters on the performance of DTPA chelating agent in modifying sandstone surface charge

Despite the positive aspects of low salinity water (LSW), this technique is relatively expensive and unavailable in some countries. Furthermore, potential problems associated with LSW such as scale precipitation in carbonate reservoirs and fine migration in sandstone reservoirs raise concerns. Chelating agents have the ability to chelate metal ions from solution, effectively reducing the salinity of seawater (SW) and mimicking the behavior of LSW. However, they mitigate the challenges associated with LSW injection. This study focuses on how the Diethylenetriaminepentaacetic acid (DTPA) chelating agent performs in modifying rock surface charge. The impact of concentration, brine salinity, potential determining ions (PDIs), oil presence, Fe3+ ions, and solution pH on the effectiveness of DTPA in altering rock surface charge was evaluated. Furthermore, wettability alteration and sand pack flooding tests were conducted to study the effect of DTPA on rock wettability and oil recovery. Results of wettability alteration, zeta potential, sand pack flooding experiments and ion concentration analysis are reported in this paper. The results showed that reducing salinity, increasing DTPA concentration, and raising solution pH changed rock wettability from oil-wetness towards water-wetness. The presence or absence of PDIs in the solution did not affect the performance of DTPA. However, by tripling the concentration of these ions in the solution, the performance of DTPA in changing rock surface charge was impaired. Based on the wettability alteration and zeta potential experiments, 5 wt% DTPA was determined as the optimum concentration. Subsequent flooding experiments revealed that injecting 5 wt% DTPA chelating agents into the sandstone sand pack after SW injection increased oil recovery from 48 % to 68.3 %. The analysis of ion concentrations also revealed a significant increase in the amount of calcium ions during the DTPA flooding, indicating the chelation of metal ions from both rock and solution and improving the wettability conditions.

Comprehensive analysis of the effect of reservoir key parameters on the efficacy of DTPA chelating agent in minimizing interfacial tension and enhanced oil recovery

Chelating agents reduce the salinity of seawater (SW) and mimic low salinity water (LSW) by binding metal ions in the solution and on the rock surface. This process decreases SW dilution costs and prevents scale formation while improving oil recovery without damaging the reservoir. This study investigates the impact of Diethylenetriaminepentaacetic acid (DTPA) chelating agent on the reduction of interfacial tension (IFT) between oil and SW, without the use of additional chemicals. For the first time, we comprehensively analyzed how reservoir key parameters (concentration, salinity, temperature, and pH) affect the performance of DTPA in reducing IFT. Additionally, rock wettability alteration and sand pack flooding experiments were conducted to evaluate the effect of DTPA on rock wettability and oil recovery. The results revealed that increasing the temperature to 75 °C and the concentration of DTPA to 5 wt% resulted in an IFT reduction to less than 1 mN/m, making the oil miscible in the DTPA solution. Salinity studies demonstrated that by increasing the solution salinity up to the optimal level, the IFT of oil/brine decreased. Furthermore, using 5 wt% DTPA solution altered the rock/oil contact angle from 143° (oil-wet) to 23° (strongly water-wet), highlighting the effect of DTPA on rock wettability alteration. Based on these findings, 5 wt% DTPA was selected as the optimal concentration, resulting in an increase in oil recovery up to 20.3% of original oil in place (OOIP) after SW injection. Elemental analysis of DTPA flooding effluent also confirmed the chelation of metal ions from rock and solution.

Insights into Enhanced Oil Recovery by Coupling Branched-Preformed Particle Gel and Viscosity Reducer Flooding in Ordinary Heavy Oil Reservoir

Viscosity reducer flooding has been successfully applied in tertiary oil recovery of ordinary heavy oil reservoirs. However, lowering interfacial tension or reducing oil viscosity, which is more critical for viscosity reducer to improve oil recovery of ordinary heavy oil, has not yet formed a unified understanding, which restricts the further large-scale application of viscosity reducer flooding for ordinary heavy oil reservoir. Moreover, when the dominant water flow channel is formed in the reservoir, the sweep efficiency decreases sharply and can affect oil recovery efficiency of viscosity reducer. Therefore, in this study, the concept of branched-preformed particle gel (B-PPG) coupling viscosity reducer flooding is proposed. The oil-water interfacial tension performance, emulsification ability, and viscosity reduction performance of three different viscosity reducers were evaluated. The enhanced oil recovery ability of viscosity reducers, B-PPG, and viscosity reducer/B-PPG composite systems was investigated by performing sand pack flooding experiments. The results show that the oil-water interfacial tensions of the three viscosity reducers S1, S2, and S3 are 0.432 mN·m-1, 0.0112 mN·m-1, and 0.0031 mN·m-1, respectively. S1 with the highest interfacial tension has the best emulsification and viscosity reduction performance, S2 is the second, and S3 is the worst. The lower the interfacial tension, the worse the emulsification stability. The sand pack flooding results show that the incremental oil recovery of viscosity reducer S2 flooding is the largest, 7.5%, followed by S1, 7.3%, and S3, 5.6%. The viscosity reducer S2 with moderate interfacial tension and emulsifying capacity has the best ability to improve the recovery of ordinary heavy oil. The incremental oil recovery of B-PPG is 12.7%, which is significantly higher than that of viscosity reducer flooding. Compared with viscosity reducing flooding, the viscosity reducer/B-PPG composite systems have better enhanced oil recovery capacity. The findings of this study can help for better understanding of enhancing oil recovery for ordinary heavy oil reservoir.

Investigation of the plugging capacity and enhanced oil recovery of flexible particle three-phase foam

In the later stage of water flooding in reservoirs, the oil production decreases. The stability of three-phase foam system is strong, enhancing oil displacement effects of ultrahigh water cut reservoirs. In this paper, the flow state of the foam system was studied by using a microscopic visualization model. Second, sandpack flooding experiments were performed to analyze the optimal plugging conditions of three-phase foam through resistance factors. Finally, single and parallel sandpack flooding experiments were carried out to analyze plugging effect and production conditions under different injection systems and permeability ratios. The research shows that three-phase foam is more stable and capable of plugging. The stable residual resistance factor after injection of the three-phase foam system is 172.75. When the foam and particles are injected simultaneously, the gas–liquid ratio is 1:1, the formation permeability is 5526.5 mD, and the plugging effect of three-phase foam is the best. The oil recovery increases by 24.9% after the injection of three-phase foam system. The three-phase foam system combines Jamin effect of foam and dynamic plugging characteristics of flexible particles. The highest oil recovery factor of 80.87% is achieved at a permeability ratio of 9.99. Three-phase foam flooding has broad application prospects.

A Visualization Study of Low-Tension Polymer Flooding for Viscous Oil Reservoirs

Summary Polymer flooding improves the sweep efficiency of viscous oil recovery over waterflooding. The low-tension polymer (LTP) flooding has the potential to improve the displacement efficiency due to low interfacial tension (IFT) without sacrificing sweep efficiency. Compared with ultralow tension (<0.001 mN/m) alkaline-surfactant-polymer (ASP) floods, LTP flooding uses a low concentration surfactant to moderately reduce the IFT (>0.01 mN/m). The objective of this research is to evaluate the performance of LTP floods as a function of IFT for a viscous oil in a 2D sandpack. Over 20 nonionic surfactants/cosolvents were tested. A series of sandpack flooding experiments were conducted in a custom-designed 2D visualization cell. The results show that short-hydrophobic surfactants 2EH-xPO-yEO can reduce the IFT to as low as 0.05 dyne/cm. Flooding experiments were performed in sandpacks with and without connate water saturation. The sandpack was water-wet for the experiments with connate water. For the experiments without connate water, the sandpack was oil-wet. A base-case secondary polymer flood (without any surfactant) with a viscosity ratio (µo/µp) of 10 showed a stable displacement and an oil recovery of 82% at the first pore volume injected (PVI). An LTP flood with an IFT of 0.1 dyne/cm also had a stable displacement front, but a higher oil recovery at 1 PVI [90% original oil in place (OOIP)]. Further reduction in IFT to 0.05 dyne/cm resulted in an unstable displacement and a lower recovery of 65% OOIP. For the experiments without connate water saturation, sandpack was oil-wet; the base-case polymer flood at a viscosity ratio of 10 showed severe fingering and a low oil recovery at 1 PVI (58% OOIP). Adding surfactants did not improve the oil recovery in oil-wet sandpacks.

Investigation of feasibility of alkali–cosolvent flooding in heavy oil reservoirs

Cold production is a challenge in the case of heavy oil because of its high viscosity and poor fluidity in reservoir conditions. Alkali–cosolvent–polymer flooding is a type of microemulsion flooding with low costs and possible potential for heavy oil reservoirs. However, the addition of polymer may cause problems with injection in the case of highly viscous oil. Hence, in this study the feasibility of alkali–cosolvent (AC) flooding in heavy oil reservoirs was investigated via several groups of experiments. The interfacial tension between various AC formulations and heavy crude oil was measured to select appropriate formulations. Phase behavior tests were performed to determine the most appropriate formulation and conditions for the generation of a microemulsion. Sandpack flooding experiments were carried out to investigate the displacement efficiency of the selected AC formulation. The results showed that the interfacial tension between an AC formulation and heavy oil could be reduced to below 10−3 mN/m but differed greatly between different types of cosolvent. A butanol random polyether series displayed good performance in reducing the water–oil interfacial tension, which made it possible to form a Type III microemulsion in reservoir conditions. According to the results of the phase behavior tests, the optimal salinity for different formulations with four cosolvent concentrations (0.5 wt%, 1 wt%, 2 wt%, and 3 wt%) was 4000, 8000, 14000, and 20000 ppm, respectively. The results of rheological measurements showed that Type III microemulsion had a viscosity that was ten times that of water. The results of sandpack flooding experiments showed that, in comparison with waterflooding, the injection of a certain AC formulation slug could reduce the injection pressure. The pressure gradient during waterflooding and AC flooding was around 870 and 30–57 kPa/m, respectively. With the addition of an AC slug, the displacement efficiency was 30%–50% higher than in the case of waterflooding.

Fabrication of surfactant-biopolymer combined system with dual viscosity reduction and mobility controllability for heavy oil reservoirs

Surfactant-polymer (SP) combined systems have been proven to be efficient for enhancing heavy oil recovery through in-situ emulsification and water thickening mechanisms due to their dual viscosity reduction and mobility controllability. In this study, 0.1 wt% anionic surfactant (fatty alcohol polyoxyethylene ether sulfate, SC) and 0.05 wt% biopolymer (xanthan gum, XG) were combined to develop a novel SP system (SC-XG). The emulsification properties including stability, droplet morphology and size distribution, as well as oil–water interfacial tension (IFT), rheology were systematically investigated. The results showed that the addition of XG into SC systems could obviously decrease the viscosity ratio of oil to displaced water (μo/μd) to 1.42 and simultaneously maintain the high viscosity reduction rate at 94.03 %, which is beneficial for decreasing the mobility ratio of water to oil (M). Besides, the emulsion prepared by SC-XG displayed stronger stability and smaller droplet size compared to those of SC after aging 2 h. Although the addition of XG into SC system could slightly increase the oil–water IFT, the viscosity and viscoelasticity were significantly strengthened and displayed main contributions to the enhancement of emulsion stability. Finally, the sand-pack flooding experiments showed that the optimum SC-XG system could enhance the heavy oil recovery by 20.20 % after brine flooding process, which exhibited dual viscosity reduction and mobility controllability. This study demonstrates the facile design and potential applications of SP system for heavy oil reservoirs.

Can hot water injection with chemical additives be an alternative to steam injection: Static and dynamic experimental evidence

Steam injection has been proven to be a technically reliable and economically successful heavy oil recovery technique. However, the large amount of energy that is required to generate the steam, the high operational cost, as well as the environmental concerns are hindering the future applications of steam flooding. Reducing steam consumption and the associated greenhouse gas emissions in thermal-based heavy oil recovery methods is a great challenge in the heavy oil industry. A possible alternative to steam injection is hot water injection with chemical additives, especially in heavy oil reservoirs with some degree of mobility. In this paper, we performed static and dynamic evaluations on both conventional and novel chemicals as hot water additives. First, laboratory screening and evaluation for chemicals as hot water additives were performed at both 21 °C and 60 °C. Chemicals tested include the following: Span 80, silicon dioxide, diethylenetriaminepentaacetic acid (DTPA), switchable hydrophilicity tertiary amine (SHTA), and deep eutectic solvents (DESs). The evaluation was based on four selection criteria: emulsion stability, viscosity change, thermal stability, and chemical cost. Second, selected chemicals were further tested as hot water additives in sand-pack flooding experiments. Based on the overall static evaluations, four chemicals were selected for sand-pack flooding experiments at hot water conditions: DES 4, DES 9, SHTA, and SiO2 c. DES 11 and DTPA can still be used as alternatives, at least for core scale experimentations, but the extremely high cost can be a serious limitation to consider when assessing these chemicals for field trials. Dynamic sand-pack flooding experiments showed that all selected chemical additives could significantly improve the recovery factor compared to the hot water or steam injection without chemicals. The recovery factors of hot water injection with selected chemical additives reached 67 %–80.5 % which were much higher than that of steam injection without chemicals (38.8 %). Emulsification was found to be an important recovery mechanism of chemical additives in hot water flooding. The experimental results provided evidence that hot water injection with chemical additives might work as a good alternative to steam injection in improving the heavy oil recovery, reducing the cost, and lessening the environmental impact.

New insights into the DPR mechanism of elastic energy released by polymer gel for enhanced oil recovery

Polymer gel was widely used as water shutoff agent in mature oil fields. And the results of single-phase plugging experiments show that the plugging rate of the polymer gel to the oil phase is lower than that of the water phase. However, the disproportionate permeability reduction (DPR) mechanism of polymer gels still remains controversial. In this paper, we used four gel formulations including polyethyleneimine (PEI) and phenol-formaldehyde crosslinked gel with and without adding laponite to investigate the effect of gel elastic property on the water shutoff mechanism. The result of sand pack flooding experiments shown that the gel with higher elastic modulus has better effects on decreasing water cut and increasing oil recovery. After adding laponite, the elastic modulus of phenol-formaldehyde crosslinked gel increased from 64.2 Pa to 192 Pa, and the elastic modulus of PEI crosslinked gel increased from 27.4 Pa to 36.5 Pa. Compared to the phenol-formaldehyde-HAPM gel, the oil recovery of laponite-phenol-formaldehyde-HPAM gel increased by 5.2% and the maximum water cut decreased by 8.3%. Besides, comparing with PEI-HPAM gel, the oil recovery of laponite-PEI-HPAM gel increased by 2.7% and the water cut dropped by 27.8%. In the meanwhile, the laponite-phenol-formaldehyde-HPAM gel with higher elastic modulus obviously swells in the formation water but almost remains constant in oil at 105°C. The mass of gel soaked in the formation water increased from 42 g to 96 g and the gel volume increased by 300% within 48 hours. This study improves the understanding of the DPR mechanism of polymer gel for water shutoff.

Influence of the Injection Scheme on the Enhanced Oil Recovery Ability of Heterogeneous Phase Combination Flooding in Mature Waterflooded Reservoirs.

With the maturity of waterflooded reservoirs, owing to serious heterogeneity, the fluid will channel through the thief zone, leading to considerable remaining oil unrecovered in the upswept area. To further enhance oil recovery (EOR) after waterflooding, the heterogeneous phase combination flooding (HPCF) was composed of a polymer, branched-preformed particle gel (B-PPG), and surfactant. For the sake of improving the economic efficiency, the influence of the injection scheme on the EOR of HPCF with an equal chemical agent cost was investigated by sand-pack flooding experiments. Then, visual plate sand-pack model flooding experiments were performed to study the swept area of HPCF under different injection schemes. Results demonstrated that the total EOR of HPCF under different injection schemes ranged from 33.5 to 39.3%. Moreover, the EOR of HPCF under the alternation injection (AI) scheme was the highest, followed by the concentration step change injection (CI) scheme, and that of the simultaneous injection (SI) scheme was the least. The visual flooding experimental results showed that the swept area of HPCF after waterflooding under the AI scheme was higher than that of the SI. Moreover, in view of qualitative analysis of remaining oil distribution, the EOR of AI of HPCF was higher than that of SI, which was consistent with the parallel sand-pack flooding results.

CO2 capture and sequestration in porous media with SiO2 aerogel nanoparticle-stabilized foams

Enhanced oil recovery (EOR) via carbon dioxide (CO2) flooding has been considered an economically feasible method for carbon sequestration. However, due to premature gas channeling that results in escape of a great deal of CO2, the degree of crude oil recovery is low, and the carbon sequestration effect is poor. In this paper, the process of CO2 sequestration was studied from a novel perspective by combining a SiO2 aerogel and a foam for oil displacement to reduce carbon emissions. The CO2 absorption capacities of aerogel nanofluids were tested with different concentrations (0.5–1.0 wt%) and rotational speeds (140–525 r/min). The effects of hindering gas channeling and carbon sequestration in three different flooding modes were evaluated via one-dimensional sandpack flooding experiments. The mechanism for CO2 capture by aerogels in porous media was explored through microscopic visualizations of displacement experiments. The results showed that the CO2 absorption capacity of aerogel nanofluids far exceeded those of water and conventional nanofluids. The CO2 + nanofluid displacement evidently controlled gas channeling and improved CO2 sequestration by forming stable foams, and the final sequestration rate was 60.8%. Moreover, compared with conventional foams, a model was proposed to describe different states of CO2 (dissolved, adsorbed, and free) in aerogel nanoparticle-stabilized foam displacement.

Experimental and Numerical Studies of Supercritical Water Flooding for Offshore Heavy Oil Recovery

Supercritical water (SCW) is a novel thermal agent that has been recently utilized for the production of heavy oil. However, a lack of knowledge about its recovery mechanisms limits the application of SCW. In this study, pyrolysis and sandpack flooding experiments were performed to investigate the mechanisms and viability of SCW flooding. Then an innovative simulation model was developed for SCW flooding. Finally, sensitivity studies on SCW flooding were conducted by the developed model. The results showed that SCW flooding yielded a 13.99% increase in oil recovery in comparison to steam flooding, indicating that SCW flooding is technically applicable to offshore heavy oil reservoirs. Heavy oil upgrading in SCW can suppress coke formation and plays an important role in oil recovery. A novel numerical model for SCW flooding was established based on a history match of experiments. The simulation results suggested that during SCW flooding, SCW could induce heavy oil upgrading to increase oil mobility, and long-term injection of SCW may cause the formation of coke deposits. Higher injection temperatures and pressures would benefit the production performance of SCW flooding. However, an unlimited increase in temperature would damage formations by significant coke deposits.