Sandpack Flooding Tests Research Articles

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.

Investigation on the Stability of Janus SiO2-n Nanoparticle-Assisted Nonionic Surfactant-Stabilized Foam and Its Application in Enhanced Oil Recovery

The stability of the foam directly impacts the final efficiency of the foam flooding in enhanced oil recovery (EOR). In the present work, a series of Janus SiO2-n nanoparticles (JSn NPs) with various modification degrees were successfully prepared and employed to improve the stability of the nonionic surfactant polyethylene glycolmonoisodecylether (PMIE)-stabilized foam. The PMIE–JS3 system with a much low JS3 NP concentration (0.1 wt %) displayed extraordinary foamability and stabilizing foam ability via the foam volume, half-life, relative volume decay, and optical microscope photograph measurements. Then, the dynamic surface tension and dilatational viscoelasticity tests were conducted to explore the mechanism. It was found that the PMIE–JS3 system with great interfacial activity and intensive interfacial film highly facilitated the generation of the foam and improved the foam stability. Moreover, the PMIE–JS3-stabilized foam exhibited outstanding stability, even under the influence of crude oil. The sandpack flooding tests indicated that the PMIE–JS3-stabilized foam could effectively plug the high-permeability channels to modify the water injection profile and consequently greatly enhanced tertiary oil recovery (∼15.3% of the initial oil in place).

Enhanced Oil Recovery from the Methyl Ester Sulfonate Derived from Flaxseed Oil: Interfacial, Adsorption and Rock Wetting Characteristics

AbstractThe current work aims at the application of fatty acid methyl sulfonated products derived from Flaxseed oil for enhanced oil recovery. The product was characterized with the GCMS (gas chromatography mass spectrometry), FTIR (fourier transform infrared spectroscopy), FESEM (field emission scanning electron microscopy), EDX (energy dispersive X‐ray analysis) and TGA (therogravimetric analysis). Conductivity tests revealed that the critical micelle concentration (CMC) of Flaxseed surfactant is 7004 ppm. The amount of surfactant loss on the sand surfaces was found to be 10.42 mg/g which was quite lower as compared to that of the previous studies. Interfacial tension (IFT) was found to decrease up to 0.25 mN/m upon introduction of Flaxseed surfactant. Also, the slug showed pseudoplastic behavior at a lower shear rate whereas it showed shear thickening behavior at a higher shear rate. Finally, sand pack flooding tests were conducted and ∼48 % of oil recovered during water flooding whereas an additional ∼28 % of the oil was recovered as improved oil recovery.

Investigation of Nanoclay-Surfactant-Stabilized Foam for Improving Oil Recovery of Steam Flooding in Offshore Heavy Oil Reservoirs.

This study presents a study of nanoclay-surfactant-stabilized foam to improve the oil recovery of steam flooding in offshore heavy oil reservoirs. The foam stability and thermal resistance studies were first performed to investigate the influence of nanoclay on the stability and thermal resistance properties of the foam system. Then, the sandpack flooding tests were conducted for investigating the resistance factor and displacement abilities by nanoclay-surfactant-stabilized foam. The results showed that the nanoclay-surfactant-stabilized foam has excellent foaming ability and foam stability at 300 °C, which can be used in steam flooding for offshore heavy oil reservoirs. The resistance factor is greater than 30 at 300 °C when the gas–liquid ratio ranges from 1 to 3, which indicated that the nanoclay-surfactant-stabilized foam has good performance of thermal resistance and plugging effect. The heterogeneous sandpack flooding test showed that the nanoclay-surfactant-stabilized foam can effectively divert the steam into the low-permeability area and improve the sweep efficiency, thus improving heavy oil recovery of steam flooding. Therefore, the nanoclay-surfactant-stabilized foam flooding has a great potential for improving oil recovery of steam flooding in offshore heavy oil reservoirs.

Enhancing the Performance of HPAM Polymer Flooding Using Nano CuO/Nanoclay Blend

A single polymer flooding is a widely employed enhanced oil recovery method, despite polymer vulnerability to shear and thermal degradation. Nanohybrids, on the other hand, resist degradation and maintain superior rheological properties at different shear rates. In this article, the effect of coupling CuO nanoparticles (NPs) and nanoclay with partially hydrolyzed polyacrylamide (HPAM) polymer solution on the rheological properties and the recovery factor of the nanohybrid fluid was assessed. The results confirmed that the NP agents preserved the polymer chains from degradation under mechanical, chemical (i.e., salinity), and thermal stresses and maintained good extent of entanglement among the polymer chains, leading to a strong viscoelastic attribute, in addition to the pseudoplastic behavior. The NP additives increased the viscosity of the HPAM polymer at shear rates varying from 10–100 s−1. The rheological properties of the nanohybrid systems varied with the NP additive content, which in turn provided a window for engineering a nanohybrid system with a proper mobility ratio and scaling coefficient, while avoiding injectivity issues. Sandpack flooding tests confirmed the superior performance of the optimized nanohybrid system and showed a 39% improvement in the recovery ratio relative to the HPAM polymer injection.

Initial screening of new generation chemicals using sandpack flooding tests for recovery improvement of gravity driven steam applications

Reservoirs containing very heavy oil or extremely heterogeneous/fractured geology are not convenient for steam flooding and even cyclic steam injection. But, steam can be used to heat the reservoir and accelerate the recovery by gravity drainage. Two well-known applications of this method are steam assisted gravity drainage (SAGD) and thermally assisted gas oil gravity drainage. Although the latter is not commercially applied, the former is a proven technology with remarkable production in Canada and Venezuela. An alternative is to use chemicals as suggested a few decades ago to alter the interfacial forces and improve microscopic displacement. This paper presents experimental results on testing – the new generation – chemicals for their capability in recovery improvement.Sandpack experiments were conducted to evaluate the incremental in oil recovery by chemical additives compared to sole steam injection. Steam and chemicals were heated and introduced to the system from separate channels at the entrance of the vertically situated sandpack (4 inch length, 2 inch in diameter). The chemicals used include thermally stable surface agents, such as anionic surfactants (AAS J1111, O352, LTS-18), non-ionic surfactants (Tween80/85, Span80/85, Novelfroth190, Triton X-100), a biodiesel (FAME), ionic liquid (BMMIM BF4), high pH solution (NaBO2), solvent (heptane, DME), and nanoparticles (SiO2). The oil selected was 27,000 cP crude.Incremental recoveries were monitored and related to the thermal stability and commercial prices of the chemicals. A comparative analysis was provided as to their contribution to the reduction of the cost (lower SOR) and chemicals were classified based on their recovery improvement performance and thermal stability using thermogravimetric analysis (TGA). Through this experimental schematic, the highest increase in oil recovery was achieved by heptane which was also cheap in comparison to the other tested chemicals. Asphaltene precipitation was quantified by conducting SARA analysis of samples taken from the sandpack flooding experiments. The nanoparticle was placed initially into the core holder and had the second-best performances in the steam-to-oil ratio (SOR). Biodiesel also improved oil recovery, but the effects need to be further investigated. The non-ionic surfactants showed great thermal stability and Span80, Tween80, as well as Novelfroth190, lowered the SOR by improving oil recovery. On the other hand, the injection of LTS-18 as anionic surfactant showed an increment of ultimate oil recovery by around 3%. As a wettability modifier, the ionic liquid proved to be profitable in rising oil recovery from the sandpack experiment in a tertiary and an initial injection attempt; however, the ionic liquid is the most cost-effective chemical of the tested candidates.

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In situ CO2 enhanced oil recovery (ICE) has great potential for the mature oil field. ICE can deliver CO2 to the targeted formation by the injection of CO2 producing agents which decompose in the reservoir to release CO2 and other oil recovery enhancing compounds. The mechanism of the ICE system was evaluated experimentally. Alkali and hydrotrope induced interfacial tension (IFT) reduction were studied with crude oils that have different acid numbers and also dodecane. The independent and combined effect of the ICE system on wettability reversal was quantified by contact angle measurement with different fluid systems and lithology. Ten one-dimensional sand pack flooding tests with different lithology and fluid systems were designed to isolate the different recovery mechanisms and study their individual contribution to the final tertiary recovery. From the experimental results, the highest IFT reduction by alkali effect was from 21 mN/m to 0.77 mN/m. The wettability of clean sandstone and sandstone aged in crude oil were responsive to different concentrations of NH3 solution. The sandstone surface became more water-wet with increase in NH3 (aq) concentration. The wettability of carbonate core samples were not strongly affected by the NH3 solution. Both aged sandstone and carbonate core samples showed significant wettability reversal from oil-wet to water-wet after the ICE treatment. After a series of sand pack flooding tests, it was shown that the effect of CO2 was more dominant in carbonate reservoirs and NH3 (aq) contribution to the tertiary recovery increased with the increase of the crude oil acid number. The results help elucidate the mechanisms in ICE and their contribution to the final oil recovery.

Contribution of Feldspar Minerals to pH during Smart Water EOR Processes in Sandstones

It has previously been suggested that a local pH increase at pore surfaces is responsible for desorption of polar oil components and wettability alteration in sandstone reservoirs, leading to increased oil recovery during smart water or low salinity injection. The pH increase can be a result of cation exchanges at clay surfaces or at other mineral surfaces present in sandstone reservoirs, such as feldspars, which is the topic of this paper. In this study, static batch tests and dynamic sandpack flooding tests have been performed to investigate the pH development in the brine phase in contact with three common feldspars, Ab-feldspar (albite), An-feldspar (anorthite), and Or-feldspar (microcline). Temperature varied between 23 and 130 °C, and brine salinity varied from 0 ppm (deionized water) to 100 000 ppm NaCl in batch tests. The sandpacks were composed of 10 wt % feldspar and 90 wt % quartz and flooded with 100 000 and 1000 ppm brines. In all tests, equilibrated brine pH was monitored to study cation-exchange reactions between the feldspars and the brine phase. The main results in this study showed that all three feldspars tested, Ab-feldspar, An-feldspar, and Or-feldspar, caused a pH increase in the brine phase at all temperatures and salinities tested and can therefore influence pH during waterflooding of sandstone reservoirs. There was a general decrease in ion exchange and pH increment when the test temperature increased for all three feldspars. The least stable feldspar, or the most reactive feldspar, in cation-exchange processes seemed to be An-feldspar, causing the highest pH at most conditions, also being least affected by increasing brine salinity.

Condensate blockage remediation in a gas reservoir through wettability alteration using natural CaCO3 nanoparticles

Wettability alteration of near-wellbore region from liquid-wetting to gas-wetting has been known as a feasible method for eliminating condensate blockage in gas condensate reservoirs. In this research, the natural CaCO3 (Bio-Ca) nanoparticles containing chitin were used as environmentally friendly and cost-effective agents which can act as nanocomposite for wettability alteration. For this purpose, their performance was evaluated on wettability alteration of the gas/oil systems by conducting contact angle measurements and sand pack flooding tests. In addition, for evaluating the stability of nanofluids, zeta potential measurement was conducted. The Bio-Ca nanoparticles were produced using cuttlebone (Sepia Pharaonis) taken from the Persian Gulf. Also, silica nanoparticle was used as a scale for comparison of its performance with the newly synthesized nanoparticle. Four influencing factors including nanofluid concentration, gas flow rate, oil type, and nanoparticle type were investigated and the optimum conditions for improving oil recovery and gas/oil relative permeabilities were also obtained using Taguchi method. The values of zeta potential implied that both nanofluids are stable at the given pH. The results of the contact angle measurement indicated that the contact angles of condensate droplet raised from 0° to 105° after treating the rock surface by Bio-Ca nanofluid with a concentration of 0.05 wt. %. This is happened because of the increase in roughness with reduction of surface free energy of rock surface along with disjointing pressure mechanism. Analysis of variance showed the importance of considering the simultaneous effect of these parameters on oil recovery and relative permeabilities for wettability alteration purposes. Results show that the optimum conditions for increasing oil recovery using Bio-Ca nanoparticles include the nanofluid concentration of 0.05 wt. %, using normal heptane as a liquid phase, and a gas flow rate of 100 cc/min. Besides, for gas and oil relative permeability endpoints as a second response parameter, the most effective parameter is gas flow rate of 55 cc/min. Results of this work are confirmed that the Bio-Ca nanoparticles play a vital role in wettability alteration, which can alter the wettability of the medium from strongly oleophilic to oleophobic due to their biostructure.

Solution Properties and Displacement Characteristics of in situ CO2 Foam System for Enhanced Oil Recovery

AbstractCarbon dioxide (CO2) foam flooding has been shown to enhance oil recovery. However, large‐scale adoption has been restricted by issues with transportation of CO2 and equipment corrosion. In situ CO2 foam generation can possibly overcome these issues. In this article, a CO2 sustained‐release system was first optimized for the CO2 production rate and production efficiency. Then, the dissolution capacity and plug‐removing ability of the sustained‐release system were evaluated. Visual experiment and parallel sand pack flooding tests were conducted to verify the formation, propagation of in situ CO2 foam, and the feasibility of this technique. The results indicated that the sustained‐release system had benign ability to lower injection pressure and improve injectability. Moreover, in situ CO2 foam flooding could obtain high oil recovery due to favorable mobility control ability, interfacial tension reduction capacity, and heterogeneity improvement. All the experiments demonstrated that the in situ CO2 foam technique has great potential for enhanced oil recovery in the Bohai oilfield.

Isolated mechanism study on in situ CO2 EOR

In situ CO2 enhanced oil recovery (ICE) has great potential for the mature oil field. ICE can deliver CO2 to the targeted formation by the injection of CO2 producing agents which decompose in the reservoir to release CO2 and other oil recovery enhancing compounds. The mechanism of the ICE system was evaluated experimentally. Alkali and hydrotrope induced interfacial tension (IFT) reduction were studied with crude oils that have different acid numbers and also dodecane. The independent and combined effect of the ICE system on wettability reversal was quantified by contact angle measurement with different fluid systems and lithology. Ten one-dimensional sand pack flooding tests with different lithology and fluid systems were designed to isolate the different recovery mechanisms and study their individual contribution to the final tertiary recovery. From the experimental results, the highest IFT reduction by alkali effect was from 21 mN/m to 0.77 mN/m. The wettability of clean sandstone and sandstone aged in crude oil were responsive to different concentrations of NH3 solution. The sandstone surface became more water-wet with increase in NH3 (aq) concentration. The wettability of carbonate core samples were not strongly affected by the NH3 solution. Both aged sandstone and carbonate core samples showed significant wettability reversal from oil-wet to water-wet after the ICE treatment. After a series of sand pack flooding tests, it was shown that the effect of CO2 was more dominant in carbonate reservoirs and NH3 (aq) contribution to the tertiary recovery increased with the increase of the crude oil acid number. The results help elucidate the mechanisms in ICE and their contribution to the final oil recovery.

A comparison of foam stability at varying salinities and surfactant concentrations using bulk foam tests and sandpack flooding

Two conventional approaches for foam screening are core/sandpack flooding and bulk foam stability tests. The former is more accurate, but requires expensive equipment and long test duration. For initial screening, the faster and cost-effective bulk foam stability tests are used to narrow down the selection to a few surfactants, which are then further tested using corefloods/sandpacks. The bulk foam stability tests have been historically used for surfactant selection at a fixed salinity and fixed surfactant concentration. The foam generated in bulk foam stability test was observed to be quite homogeneous, whereas foam generated through porous media is more heterogeneous; hence, a modification to the bulk foam test was made in that a small quantity of quartz river sand was placed at the bottom of the test tube for generating foam that simulates porous media. To evaluate the use of bulk foam and modified bulk foam stability tests for screening and optimizing salinity and surfactant concentrations, sandpack flooding tests were conducted at a range of salinities, and surfactant concentrations and results were compared. Bulk foam stability tests results were found to be compatible with sandpack results for surfactant concentration optimizations, but showed significant deviation for salinity optimization. The modified bulk foam stability tests, however, showed better agreement with sandpack results in both salinity and surfactant concentration tests.

Experimental, modeling and simulation investigations of a novel surfmer-co-poly acrylates crosslinked hydrogels for water shut-off and improved oil recovery

Nowadays, chemical and petroleum engineers give incremental attention to different techniques of chemical enhanced oil recovery (CEOR) owing to continual and scared energy consumption, and enormous trapped oil reserves after primary and secondary flooding. Hydrogels are three-dimensional crosslinked macromolecules which retain excessive water amounts. In this research, we investigate the synthesis and spectroscopic characterization of Lutensol AT 25 E -Methacrylate surfmer, then its copolymerization with acrylates monomers through free radical polymerization, which considered an effective tool to generate block copolymers with hydrophilic and hydrophobic moieties. Characterization and structure determination occurs by traditional spectroscopic techniques. Since mathematical formulation and prediction of hydrogel swelling ability has incremental consideration recently, so mathematical modeling of different rheological properties including swelling performance, post-degraded gel viscosity, gel strength, viscoelastic properties as well as shear thinning effects, salinity resistance, and long-term thermal aging was investigated at simulated harsh reservoir conditions. Modeling analysis showed that the Herschel-Bulkley model fits effectively the stress performance of the hydrogel suspensions, while the power law model fits the viscosity-shearing behavior. Dynamic properties examined by oscillatory tests indicating that hydrogel suspension exhibits viscoelastic performance since elastic modulus (G′) predominate viscous modulus (G″). On lab scale, sandpack flooding tests performed on a linear assembly at imitated reservoir environment, where the results indicate that the hydrogel able to reduce water permeability, adjust profile conformance, so increase incremental oil recovery up to 85.35% and alter rock wettability which assessed through relative permeability curves at different water saturation. On a field scale, a simulated run on actual reservoir data written by Fortran 90 visual studio carried out through UTCHEM software to evaluate hydrogel compatibility as an enhanced oil recovery candidate.

Hydrophobic modified silica particle (HMSP)-stabilized cottonseed oil emulsion for oil recovery enhancement

ABSTRACTIn this work, a novel water plugging agent, hydrophobic modified silica particle (HMSP)-surfactant-stabilized cottonseed oil emulsion, for oil recovery enhancement was developed. The stability and rheology experimental results displayed that the synergistic interaction between the HMSP and surfactant was formed, which could remarkably improve the stability and increase the viscosity of the emulsion system. The microscopic visualization tests suggested that there was a bicontinuous structure in the HMSP-surfactant-stabilized emulsion. Moreover, the sand pack flooding tests showed that the sweep and displacement efficiency could be significantly enhanced after HMSP-surfactant-stabilized emulsion injected. The blocking rates of HMSP-surfactant-stabilized emulsion and individual surfactant-stabilized emulsion are 98.7% and 52.9%, respectively. The above results can be considered as a guidance in the design and studies of HMSP-stabilized emulsion for a selective plugging.

Study of polymer-enhanced emulsion flooding to improve viscous oil recovery in waterflooded heavy oil reservoirs

Emulsion flooding is an effective enhanced oil recovery (EOR) process for waterflooded heavy oil reservoirs, which is not suitable for the application of thermal recovery methods because of economic issues or technical impediments. This study demonstrated the experimental investigation of polymer-enhanced emulsion to improve the viscous oil recovery in waterflooded heavy oil reservoirs. It was indicated in the emulsion stability and rheology studies that the polymer HPAM not only acted as a thickener to slow down the rate of creaming by increasing the water viscosity, but also enhanced the strength of O/W interface by increasing interfacial shear viscosity, resulting in a significant increase of the stability and bulk viscosity of emulsion system. The results of sandpack flooding tests showed that an incremental oil recovery of more than 30% of original oil in place (OOIP) over water flooding could be obtained by polymer-enhanced emulsion flooding for heavy oil with the viscosity of 350mPas at 50°C. The micromodel flooding studies indicated that the EOR mechanisms of polymer-enhanced emulsion were attributed to the reduction in mobility ratio due to higher emulsion viscosity, resulting in dramatically improvement of sweep efficiency. Besides, biodiesel could reduce the heavy oil viscosity to improve the mobility of heavy oil, and the surfactant could emulsify the heavy oil in water to form O/W emulsions, thereby improving the displacement efficiency. The results of these studies showed that polymer-enhanced emulsion flooding is a promising process to improve oil recovery in waterflooded heavy oil reservoirs.

Experimental Evaluation of a Surfactant/Compound Organic Alkalis Flooding System for Enhanced Oil Recovery

Monoisopropanolamine (MIA) and monoethanolamine (MEA), which are two kinds of organic alkalis, present favorable potential for enhanced oil recovery. When MIA and MEA are respectively applied, the minimum oil/water interfacial tension (IFT) can be reduced to about 1 mN/m, the crude oil can be emulsified, and the originally oil–wet sand surface can be altered to weak water-wet status. To display the synergistic effect of surfactant and organic alkalis, a surfactant/compound organic alkalis (MIE/MEA) flooding system (SMM), which consists of 0.10 wt % SDBS, 0.15 wt % MIA, and 0.10 wt % MEA, is screened. This system can reduce the minimum oil/water IFT to an ultralow value which contributes to the emulsion stability. Results of sandpack flooding tests indicate that although the incremental oil recovery can be continuously enhanced with the increase of the SMM slug size, there is an optimal injection size (0.8 PV in this study) when the expense is taken into consideration. As for the effect of the injection ty...

Enhancing heavy-oil recovery by using middle carbon alcohol-enhanced hot polymer flooding

In this paper, the effects of middle carbon alcohol-enhanced hot polymer flooding for improving heavy-oil recovery were investigated by using several sandpack flooding tests. Before that, the effect of different middle carbon alcohols on viscosity reduction of heavy oil were examined. Then, a new method was developed to examine the diffusion of middle carbon alcohols from water to heavy oil and its effect on viscosity reduction of heavy oil. The results show that the effect of middle carbon alcohols on reducing heavy-oil viscosity increases with their carbon number; Besides, the middle carbon alcohols can diffuse from water to heavy oil to significantly reduce its viscosity, and the viscosity reduction effect increases with temperature, strring time in a certain range. Sandpack flooding tests show that injection of hot polymer and addition of middle carbon alcohols can both effectively enhance heavy-oil recovery; The effect of middle carbon alcohol-polymer flooding increases with the temperature of polymer solution and the injection rate of polymer solution.

Experimental study of water shutoff gel system field parameters in multi-zone unfractured gas-condensate reservoirs

Excess water production during gas production causes serious operational problems and, may shutoff the wells. Polymer gel is one of the water shutoff (WSO) methods extensively used in mature gas fields in the recent years. In this research, Cr (III)-acetate sulfonated polyacrylamide hydrogels were applied in porous media with radial flow. In order to obtain gel treatment conditions with desirable performance, some sandpack-flooding tests were designed. By statistical design of the experiments using central composite, the sandpack-flooding tests were conducted to investigate the effect of gel penetrated area and reservoir porosity on the WSO efficiency. The results showed that lower gel penetrated depth led to lower gas-condensate permeability reduction and, the utmost reduction of water permeability was in a critical depth of gel penetration. In optimum conditions, a gel penetration of 0.96 cm and a porosity of 31.46% had RRFg (gas-condensate residual resistance factor) of 1.83 and RRFW (water residual resistance factor) of 5510, respectively. Some tests through multi-zone sandpacks were carried out to examine the effect of layers with different porosities and crossflow presence. Multi-zone sandpacks with crossflow between the gas-condensate and water-producing zones showed RRFW in a range of 28.2–244.7. However, the selectivity increased from 90 to 99.9% without crossflow. It was found that the chance of successful WSO treatment increases when the higher permeable layers are over the lower permeable layers.

β-Cyclodextrin associated polymeric systems: Rheology, flow behavior in porous media and enhanced heavy oil recovery performance

This proof of concept research evaluates an approach to improve the enhanced heavy oil recovery performance of conventional polymers. Three associated polymeric systems, based on hydrolyzed polyacrylamide, xanthan gum, and a novel hydrophobic copolymer, were proposed in this work. The results of the theoretically rheology study indicate that these systems offer superior viscoelasticity and pronounced shear-thinning behavior due to the “interlocking effect”. As a result of the surfactant collaboration, the dynamic interfacial tension between oil and polymer solution can be reduced by two orders of magnitude. Sandpack flooding tests demonstrated the capacity of the developed systems in mobility control during propagating in porous media, and the adsorption behavior was represented by the thickness of the adsorbed layer. The relationship between microscopic efficiency and capillary number indicated that the associated systems can significantly reduce the residual oil saturation due to the synergistic effect of the mobility reduction and surface activity, and the overall recovery efficiency was raised by 2–20% OOIP compared to the baseline polymers.

Enhancing Heavy-Oil Recovery by Using Middle Carbon Alcohol-Enhanced Waterflooding, Surfactant Flooding, and Foam Flooding

Previous studies have shown that the addition of low carbon alcohols can significantly enhance oil recovery in surfactant flooding and alkaline flooding. In this paper, the influence of middle carbon alcohols (including n-butanol, n-pentanol, isoamyl alcohol, and n-hexanol) on waterflooding, surfactant flooding, and foam flooding for enhanced heavy-oil recovery was investigated. Foaming tests, oil viscosity measurements, IFT measurements, emulsification tests, and sandpack flooding tests were conducted to investigate the effects and mechanisms for enhanced heavy-oil recovery by addition of middle alcohols. The results show that the added middle carbon alcohols has no obvious effect on the reduction of IFT between oil and surfactant solution; however, they can reduce the viscosity of heavy oil and can greatly enhance the foaming property and the emulsifying property of surfactant solution. The sandpack flooding results show that the heavy-oil recovery can be enhanced significantly through the addition of m...