Flooding Experiments Research Articles

Monitoring fluid migration using in-situ nuclear magnetic resonance core flooding system integrated with fiber optic sensors: A proof of concept

In-situ nuclear magnetic resonance (NMR) core flooding system has enabled researchers to monitor several rock properties such as porosity, pore size distribution, and fluid saturation along the tested samples with high resolutions and under reservoir conditions. However, spatially resolved rock strength/mechanical property alteration coupled to fluid migration/substitution remains poorly characterized. To this end, Fiber Bragg Grating (FBG) multiplex sensors were integrated with NMR core flooding system to monitor rock strength changes, or generally speaking, to observe hydro-mechanical-chemical coupling mechanisms during core flooding tests. In this study, we present a novel approach on how to conduct core flooding experiments, while simultaneously monitoring NMR and FBG strain response of the tested limestone plug. The NMR cell was modified to integrate FBG technology without impeding the NMR signal and core flooding high pressure/temperature capacity. A high spatial resolution optical fiber was attached onto the sample radial surface. The results show the successful association of NMR and FBG sensors to track any change at each stage of brine injection. The FBG is capable of measuring the rock strain variations induced by rock-fluid interactions during brine injection, allowing it to capture the fluid front location along with the sample and at a faster rate than the NMR.

Recovery efficiency and characteristics of long core by CO2 flooding in low permeability sandstone reservoirs

CO2 flooding is an economical and efficient enhanced oil recovery technology, however, it is difficult for conventional short core experiments to provide accurate parameters for the later on-site optimization scheme. In this paper, on the basis of long core flooding experiments and applying NMR technology, we quantitatively evaluated the recovery efficiency and remaining oil distribution characteristics by CO2 in low-permeability sandstone reservoirs from a microscopic perspective, and explored the potential of CO2 flooding in low-permeability sandstone reservoirs. Results showed that with the CO2 injection pressure increase, the recovery efficiency of the long core increased and the ultimate recovery was 65.3%. Recovery efficiency of short cores at the inlet, middle and outlet decreases successively, but the change range was not large, and all of them are around the recovery efficiency of long core. In addition, at low injection pressure, almost all CO2 went into the larger pores to replace oil. As increased pressure, the oil started to be produced from the smaller pores, but at 22 MPa, the recovery efficiency in larger pores (76.88%-83.38%) was still higher than that of smaller pores (68.73%-72.74%). Which provided a guide for optimizing the CO2 enhanced oil recovery method in the field.

Digital Core Analysis as an Efficient Tool for Acid Treatment Optimization

Digital rock workflow for acid treatment optimization is developed. It includes construction of a digital rock model based on X-ray microtomography, running a set of multiscale digital experiments and a number of acid flooding experiments on rock samples for the model tuning. Here, we present results of application of the developed workflow for Austin chalk rock treatment by hydrochloric acid on core samples of 8 mm in diameter. Pore-scale simulations were performed using high-resolution 3D microCT models to determine the dependencies of rock permeability, active surface area and effective reaction rate on actual porosity. These properties were used to populate the laboratory-size core models, and Darcy-scale numerical approach was applied to simulate the dissolution at different injection rates. The core-scale simulations demonstrated inhomogeneous character of dissolution process leading to wormhole development in a certain range of injection rates. In parallel to numerical simulations, laboratory experiments on the same rock samples were performed at flow rates close to the optimal regimes followed by microCT imaging of wormhole structures. This information was then used to tune the model parameters. After that, the dependencies of the number of pore volumes injected until the breakthrough (PVBT) on the injection rate were obtained numerically for all the cores considered.

Investigation of the Selectivity of the Water Shutoff Technology

High water-cut oil production is one of the major issues in the petroleum industry. The present study investigates different profile control solutions, with an emphasis on selective methods and materials that mostly decrease the permeability of water-saturated reservoir areas. To achieve the selective water flow blockage in fractured porous media, the sodium silicate-based gel-forming composition was developed. The test procedure was created to assess selective and strength characteristics of the presented composition. According to the results of this procedure, adding polyatomic alcohols to the mentioned composition enhances its hydrophilic behavior in water-saturated rocks (work of adhesion increases from 117 to 129 mJ/m2) and reduces the hydrophobic behavior in oil-saturated rocks (work of adhesion drops from 110.3 to 77.4 mJ/m2). The selectivity of the composition performance is validated by its higher wettability of water-saturated reservoir rocks compared with oil-saturated; thus, the composition creates a more stable water shutoff barrier when entering the water zone in a formation. As a result of core flooding experiments in natural, fractured, porous core samples, the efficiency of the water blocking capacity of the composition was proved. In addition, these tests showed the selectivity of the composition because the permeability decrease in water-saturated core samples was higher than in oil-saturated ones. The experimental value of the selectivity coefficient was 152.14.

Application of surfactants in enhancing oil recovery from tight carbonates: Physicochemical properties and core flooding experiments

Surfactant formulations are optimized according to reservoir conditions to ensure their efficiency in enhanced oil recovery (EOR). This experimental study aimed to examine the EOR performance of a group of novel Alfoterra surfactants, which are based on alcohol propoxy sulfates. The performance of the Alfoterra surfactants (anionic) was compared to that of sodium dodecyl sulfate (SDS, anionic), dodecyltrimethylammonium bromide (DTAB, cationic), cetyltrimethylammonium bromide (CTAB, cationic) and t-octylphenoxypolyethoxyethanol (Triton X-100, nonionic). First, surfactant formulations were optimized based on their critical micelle concentration as well as their aqueous stability at 55 °C under different salinities. Next, the effects of the stable surfactant formulations on the interfacial tension (IFT) and rock wettability were examined. It was shown that the presence of the surfactants and the increase in salinity both caused a significant reduction in the oil-water IFT. Additionally, all surfactant formulations altered the wettability of carbonate rock from intermediate-to water-wet conditions. Next, tests of surfactant adsorption onto a carbonate-rock adsorbent were performed, showing that the anionic surfactants tend to adsorb more onto carbonates compared to other surfactants. Finally, core flooding tests involving medium-viscosity oil recovery from tight carbonate cores showed an EOR of 25.7–39.4% of original-oil-in-place above that achieved using regular waterflooding.

Improvement of supercritical carbon dioxide foam performance for EOR in sandstone reservoirs: An experimental and optimization study

Carbon capture is a way of reducing CO2 emissions by capturing and storing CO2 in geological reservoirs, deep saline aquifers, or using it for enhanced oil recovery (EOR). EOR using CO2 is currently one of the most successful EOR techniques. Unfortunately, gas injection techniques suffer from high gas mobility and gravity override, which decrease the macroscopic sweep efficiency and ultimately the oil recovery. Foams may tackle these issues by decreasing gas mobility and gravity override; however, CO2 generates weak foam at its critical conditions, and most reservoirs exist at high pressures and temperatures that exceed CO2 critical conditions. In these conditions, these issues may be tackled by the partial replacement of CO2 with nitrogen, as mixtures of CO2 and N2 can produce strong foam compared to the weak foam generated by CO2 alone. Different core flooding experiments were conducted to investigate the effect of changing the CO2/N2 ratio, injection rate, and foam quality on the performance of the mixed foam. The results show that the foam quality, injection rate, and CO2/N2 ratio must be optimized for enhanced oil recovery. It was observed that increasing N2 content above 20% improved the foam properties; however, it did not result in higher recovery. In addition, decreasing N2 content below 10% did not help the recovery. The optimized foam quality appears to be approximately 80% with a CO2/N2 ratio of 4:1 and 0.5 cc/min injection rate to obtain the highest oil recovery. This study provides an effective and simple solution for improving and optimizing the parameters for mixed foam injection under reservoir conditions, which can produce more oil and store significant quantities of CO2 underground.

Experimental Study on Early Polymer Injection Timing of Heavy Oil Reservoir in Bohai Sea

The polymer flooding of ordinary heavy oil reservoirs in Bohai Sea can improve the crude oil recovery by advancing the injection time of polymer flooding. The better the injection time is, the higher the enhanced recovery is, and the greater the income is. Based on Bohai Oilfield, the polymer application system was characterized in the laboratory, and then polymer flooding experiments were carried out at different times using one-dimensional core model. The results show that: 1) polymer AP-P4 can establish good mobility control ability (RF=107, RRF=28.5) under the target reservoir conditions; 2) Under the experimental conditions, the best time for polymer injection is to switch to polymer injection after 0.203PV water injection, and the oil recovery can be increased by 27.73%. Early polymer injection technology is very beneficial to polymer flooding in offshore oil fields.

Investigation of Foam Flooding Assisted by Non-Newtonian and Novel Newtonian Viscosifying Agents for Enhanced Oil Recovery.

One of the main reasons for foam flooding enhanced oil recovery (EOR) is mobilizing oil left in the reservoir after primary recovery (depletion by pressure difference solely) and water flooding. However, expanding the infrastructure for certain foam EOR projects might be necessary as more wells are required, or a different well pattern is necessary. This study aims to study the effect of Newtonian and non-Newtonian viscosifying agents to assist foam flooding under the porous medium condition and to compare the results. Furthermore, this paper attempts to investigate the use of glycerol as a novel promising economic and ecological candidate instead of polymers. The shear rate inside the core was calculated based on the literature, which was combined with viscometric measurements in order to form four pairs of equal apparent viscosity. The differences and overlap within the core flooding experiments with foam generated by Newtonian and non-Newtonian fluids were observed by examining the mobility reduction factor under transient and steady-state conditions and by calculating the gas fraction present in the core. It was concluded that glycerol in core flood experiments could reach the same mobility reduction factor of about 1600 as polymer solutions with the same apparent viscosity, as long as the viscosity of the injected solution is reasonably low. Moreover, glycerol even reached the maximum mobility reduction factor faster than the foam generated by the polymer solution.

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.

Potential for improving the efficiency of terrigenous oil deposits waterflooding with the use of low salinity technology at fields of the Tatarstan Republic

This article is devoted to the review of one of the currently relevant methods of enhanced oil recovery – low-salinity waterflooding (LSW) – on the example of terrigenous Tulian, Bobrikovian and Devonian reservoirs of the Tatarstan Republic fields. The first part of review contains information about the key processes underlying this method, such as swelling and migration of clay particles and wettability alteration, as well as the mechanisms that explain these processes, which include cation exchange, multicomponent ion exchange, electric double layer expansion, etc. Their understanding, in turn, contributes to the identification of the main factors, the presence or absence of which at the field allows us to give a preliminary assessment of LSW application. There are main factors: the presence of clay particles, a significant content of Ca2+ and Mg2+ ions, as well as multivalent ions in formation water, low formation permeability, reduced oil viscosity, an increased content of acidic and especially basic components in oil and, as a result, a hydrophobic type of initial rock wettability. Then, examples of using the method in other fields are given and the results of laboratory studies, including the measurement of the contact angle, core flooding experiments, are briefly highlighted. A preliminary screening is carried out on the basis of geological and field data from several fields of Tatarstan Republic, candidate fields are identified and a preliminary conclusion about LSW application in this region is made. The positive factors for the reservoirs under consideration, identified at the preliminary screening stage, include low formation temperature, high salinity of formation water with a significant content of divalent cations and the potential to shift the pH level from the current slightly acidic level towards increased alkalinity, and an increased content of polar oil components. In addition, the reservoirs of the Tulian and Bobrikovian horizons are characterized by the presence of clay particles, and the Devonian reservoir are characterized by a reduced oil viscosity coupled with an increased oil base number.

Experimental investigation of flow diversion and dynamic retention during polymer flooding in high salinity fractured carbonates using CT imaging

The successful record of polymer flooding in improving oil production from sandstone reservoirs has encouraged the expansion of its application in carbonate reservoirs. However, the existence of natural fractures, high permeability contrast, and harsh conditions of carbonate reservoirs provide significant challenges for achieving an optimized performance of polymer flooding. It is crucial to establish an appropriate polymer that can offer an optimum flow behavior for in-depth mobility control under reservoir conditions. This study presents in-situ saturation monitoring to evaluate the mobility control effect and identify the flow diversion during polymer injection in high salinity fractured and unfractured carbonate rocks. A synthetic polymer, acrylamido tertio-butyl sulfonate (ATBS) was used and prepared in 200,000 ppm brine salinity. The flow behavior of polymer solution was investigated in bulk rheology tests followed by single-phase core flooding experiments. The flooding apparatus was coupled with a CT scanner to produce 3D images for determining the fluid saturation distribution and inaccessible pore volume (IPV) in real time. Accordingly, flow diversion across fracture-matrix system during polymer injection and the dynamic retention after brine post-flush were identified. The flow experiments showed a shear thickening behavior for the injected polymer solution in the fractured core and no degradation was noticed under in-situ conditions. Based on the fluid saturation profiles, the established flow resistance in the fracture region was prominent to induce flow diversion from the fracture into the matrix. Compared to the case in unfractured rock, the IPV in the fractured rock was approximately 2.5 times higher which was at 53% after 1 PV injection. An additional 23% of IPV was subsequently penetrated upon a continuous polymer injection for 5 PV. In post-flush stage, the fractured core retained about 87% of the injected polymer solution at 1 PV which was then minimized to 7% after 10 PV injection. The entrapped polymer in the fractured core was potentially induced by hydrodynamic retention. This work ascertained the potential of polymer flooding to effectively sweep the fractured carbonates at high salinity environment under certain circumstances for a better conformance.

Experimental study on water injection and stratified steam explosion at the top of metal molten pool

Metal layer induced heat flux focusing effect of In-Vessel melt Retention (IVR) strategy has become important weakness for high power core (APR1400, CAP1400). Injecting water on top of the metal layer can take heat away from the top and relief from heat flux focusing effect, but there can be stratified steam explosion and hydrogen risk. In this study, SUS321 steel melt pool (∼1600℃) top flooding experiments have been conducted, under diverse injecting modes, for exploring coolability and steam explosion risk. The tests results showed that the water jet, whose injecting velocity was 10 m/s, could be able to pierce the steel free surface and trigger steam explosion, and concurrently, the larger injecting flux was, the more violent steam explosion became. But steel melt pool was cooled quietly under water droplets injecting mode. The light refractory oxide layer, floating at the steel melt pool surface, could build a barrier to separate the injecting water.

Study on the synergism of cellulose nanocrystals and janus graphene oxide for enhanced oil recovery

The usage of nanoparticles in enhanced oil recovery (EOR) has been numerous due to their captivating ultra-small size and eccentric thermal, electrical, and interfacial modification properties. However, nanoparticles in their bare form could suffer from several drawbacks due to possible stability issues. The incorporation of a synergist into the preparation of nanofluid has been a promising approach to alleviate stability issues. In the present study, a novel fusion nanofluid (FN) composed of a cellulose nanocrystal (CNC), and an amphiphilic graphene oxide-based Janus nanosheet (AMGO) is presented. We synthesized the CNC using enzymatic hydrolysis and ultrasonic processing from the cellulosic waste extracted from Eucheuma cottonii, a marine-based crop. Moreover, we synthesized the AMGO from a green immobilization method. Subsequently, the CNC and AMGO were combined via sonication to form FN. The CNC, AMGO, and FN were characterized appropriately using spectroscopy and microscopy techniques. As controls, CNC and AMGO were tested alongside FN in terms of rheological properties measurements, contact angle measurements, and the core flooding experiment on Berea and Edwards White core samples. Based on the rheology measurements, FN exhibited a more elastic behavior than CNC, demonstrating better dispersibility that could be attributable to the formation of a more resilient 3D network structure via hydrogen bonding synergisms between CNC and AMGO. Furthermore, FN reduced contact angles from ∼166° to ∼35° in the Berea, and ∼172° to ∼25° in the Edwards White, signifying excellent favorable wettability alteration in both rock types. Through core flooding experiments, FN attained additional oil recoveries of 22.96% and 12.24% from Berea and Edwards White, respectively, which were up to 16.04% and 3.37% more than the control runs. As opposed to CNC, the injection of FN did not result in excessive pressure drop readings, attributing to the better dispersibility and better wettability alteration abilities. Nonetheless, the developed FN comprising CNC and AMGO could be referenced for the future design of greener nanofluid with optimistic EOR efficacies.

Experimental Study on the Diversion Characteristic of a Viscous Fluid in a Heterogeneous Reservoir.

As a typical feature of a reservoir, heterogeneity is the main reason for low oil recovery and the poor effect of acidizing measures. Diversion is the main measure to improve the acidizing effect. Over the years, technological progress has mainly focused on the material development of diverting agents. In this study, the diverting effect and influencing factors for a viscous fluid were systematically studied by the heterogeneous dual-core flooding experiment. The results are as follows: First, increasing the displacement pressure in heterogeneous reservoirs can improve the diverting effect, which is consistent with maximum differential pressure and injection rate (MADPIR) theory, but the diverting effect is weak. The injection pressure difference is increased by 50 times, and the diverting effect is improved by 16.27% at most. Second, taking a viscous fluid as the stimulation fluid can partially realize the diversion for heterogeneous reservoir and further improve the acidizing effect, and the breaking through PV can be improved by 78% at most. Using a viscous fluid as a diverting agent can achieve 100% balanced acid injection. Third, compared with a viscoelastic surfactant, a relatively uniform and stable polymer solution as the diverting agent has the possibility to completely block the low-permeability layer. So, a 5% viscoelastic surfactant as the diverting agent is more suitable for acidizing. Finally, any diverter injected into the formation will enter all layers. The conclusion that the diverting agent only enters the high-permeability layer but not the low-permeability layer is not tenable. Diverting acidizing is only effective for near-well zones, which is difficult to fundamentally solve the seepage problem of heterogeneous reservoirs.

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.

Effects of different gases on the performance of foams stabilized by Cocamidopropyl betaine surfactant and silica nanoparticles: A comparative experimental study

Application of CO 2 gas in foam enhanced oil recovery (EOR) processes has emerged as a win-win strategy for achieving higher oil recovery factor and reducing greenhouse gas emission, which can significantly help the protection of the ozone layer from depletion. However, lower stability of CO 2 -foam, as compared to the N 2 - and CH 4 -foams, has tempted us to examine combinations of CO 2 with these gases to not only improve the stability of the produced foam but also have CO 2 as the gaseous phase of the foam. In this study, we investigated the effect of different gases and the mixture thereof on the performance of foams in EOR while the aqueous phase of foams is a constant mixture of Cocamidopropyl betaine surfactant (0.03 wt %) and silica nanoparticle (0.1 wt%). To this end, seven different gases, including N 2 , CO 2 , CH 4 , 80% N 2 + 20% CO 2 , 80% CH 4 + 20% CO 2 , 50% CH 4 + 50% CO 2 , 50% N 2 + 50% CO 2 were used as the gases phase for foam generation, and the performance of the produced foams were examined through the following experiments: bulk foam stability tests, apparent foam viscosity measurements, and core flooding tests. The results of foam stability tests showed that half-life time for the CO 2 -, CH 4 -, and N 2 -foams are 13.5, 17.0, and 44.0 min, respectively. Also, as revealed from apparent viscosity measurements, the N 2 - and 80% N 2 +20% CO 2 foams have higher apparent foam viscosity values followed by 50% N 2 +50% CO 2 foam. Furthermore, we showed that a combination of 80% N 2 + 20% CO 2 as the gaseous phase for foam generation could not only improve CO 2 -foam stability, as compared to other foams, but also can substantially increase ultimate oil recovery (56.6 %OOIP), even more than that for N 2 foam (48.6 %OOIP), obtained from core flooding experiments.

Displacement efficiency and storage characteristics of CO2 in low permeability reservoirs: An experimental work

Over the past decades, CO2 flooding in low-permeability porous media has continued to grow. Furthermore, propelled by the current movement toward CO2 sequestration, the flooding of CO2 is expected to further increase. Thus, it is of scientific significance to study the mechanism of displacement of CO2 flooding as well as the CO2 storage characteristics. In this study, CO2 miscible/immiscible flooding experiments were conducted on two low permeability samples to study the difference between them. Specifically, the effect of oil displacement and CO2 storage coefficient for different displacement models were measured and compared. In addition, nuclear magnetic resonance (NMR) tests and frozen pelleting experiments were conducted. The NMR tests clarified the lower limit of pore throat where oil can be displaced by CO2 miscible/immiscible flooding. Furthermore, the frozen pelleting experiments analyzed the distribution characteristics of the remaining oil before and after CO2 miscible/immiscible flooding. The investigation showed that the development efficiency of CO2 miscible flooding is higher than CO2 immiscible flooding in low permeability reservoirs. The results also indicated that CO2 miscible flooding increases the recovery of hard-to-produce semi-bound oil phase and CO2 storage coefficient with CO2 miscible displacement is more significant than that with CO2 immiscible flooding. The data from this study is a critical input for reservoir simulation, which sheds light on the CO2 miscible/immiscible flooding in low permeability reservoirs.

The effect of clay on initial and residual saturation of hydrogen in clay-rich sandstone formation: Implications for underground hydrogen storage

Understanding wettability in rock-brine-hydrogen systems is essential for dependable predictions of capillary/residual trapping in clay-rich sandstone formations. Despite being the most used technique, wettability assessment based on contact angle measurements is confronted with inherent uncertainties that limit its reliability. In contrast, core flooding techniques provide a more direct and realistic picture of wettability and its time evolution. Nuclear Magnetic Resonance (NMR) allows us to evaluate the initial and residual hydrogen saturations and distribution along the core specimen. It is a fast, reliable, and effective way of inferring the impact of wettability on hydrogen migration, and residual trapping in prospective geo-storage rock formations. Recent publications have reported the evaluation of wettability in a brine-hydrogen-rock system where the rock is a clean sandstone (no clays). Here we evaluate the impact of the presence of clays in a sandstone, which has not been reported yet. NMR monitoring was employed to characterize the initial and residual hydrogen saturations in the Bandera Grey (BG) sandstone. To investigate the impact of clay minerals on hydrogen saturation, same rock sample was characterized in its natural state, and after heating it to 700 °C for 12 h in an air environment to burn off clay minerals, During the NMR core flooding experiments, ten pore volumes (PVs) were injected/withdrawn during the drainage/imbibition cycles at a fluid injection rate of 2 mL/min under room temperature and 1000 psi confining pressure. Due to the hydrophilicity of quartz and clay, the tested BG sandstone (clay-rich sandstone) shows a significant residual/trapped saturation (∼3.5% can be reproduce); therefore, clay-rich sandstone may not be ideal for hydrogen storage unless cushion gas is used.The results show that initial and residual hydrogen saturations were slightly changed after firing (from 16% to 18% for initial and from 14% to 13% for residual). This also suggests that the wettability of the BG sandstone-brine-hydrogen system is slightly impacted by clay content and type. We also observed that clay firing at 700 °C has little effect on the porosity and gas permeability of the BG sandstone. Moreover, X-ray powder diffraction (XRD) results showed that quartz content increases from 68.1% to 76.2%, Kaolinite transformed into illite and clinochlore disappeared. The disappearance of chlorite after firing suggests that it is transformed into another clay type.

An experimental study of pore-scale flow dynamics and heavy oil recovery using low saline water and chemical flooding

We report a quantitative analysis of pore-scale flow dynamics and displacement behavior of heavy oil recovery at the micro and macro-scale to optimize different chemical flooding processes for enhanced heavy oil recovery. Microscopic studies are performed using micro-particle image velocimetry, which includes low saline water followed by chemical floodings in a 2D porous micromodel to visualize and quantify the displacement process and the oil recovery. The phenomena such as fluctuating flow, flow direction reversal, viscous fingering, film formation around cylinders, unsteady flow behavior, and sudden velocity jumps are observed during low salinity water flooding. Polymer flooding results in no significant change in trapped oil configuration. Alkali-polymer solution injection improves oil recovery as it interacts with crude oil, which results in higher in-situ emulsification, interfacial tension reduction, and change in the contact angle to extremely water-wet conditions. Core flooding experiments are performed to understand the macroscopic behavior and recovery potential of different flooding processes at simultaneous and separate injection modes. The core flooding results showed that the overall heavy oil recovery is 75.37% by simultaneous injection of chemical slugs; however, a separate injection of individual chemical slugs yields lower oil recovery in the case of alkali-surfactant-polymer flooding than the simultaneous injection case. Here, the combined microscopic and macroscopic study provides information about the mechanisms and oil recovery by different chemical flooding processes through the porous medium.

Different tolerance of three typical riparian plants (Cynodon dactylon, Alternanthera philoxeroides, and Acorus calamus) to different depths of waterlogging caused variations in soil nutrient release and microbial diversity

Abstract Water-level changes in the water-level fluctuating zone (WLFZ) promoted soil and plants to release nutrients into the water, threatening the water health in the reservoir. Plant restoration in the WLFZ is also an important way to reduce the nutrient release in order to select plants that can effectively reduce the release of soil nutrients under changing water levels. This study conducted a flooding experiment to reveal the difference in the change in soil physico-chemical properties and microbial communities with various plants under different water-level conditions. The flooding experiment began at the end of September 2020 and was planted with three dominant plants common to reservoirs, namely Cynodon dactylon, Alternanthera philoxeroides, and Acorus calamus. Our study found the three common dominant plants along the reservoir, and C. dactylon had a good adsorption capacity for nitrogen and phosphorus when it was flooded with shallow water, decreasing soil nutrients during the drying period. After a wetting–drying cycle, there was an obvious and significant (p < 0.05) divergence among soil microbial community structures between N0 and D1, D2, and D3, respectively. This study could provide sufficient reference information for plant selection and the assessment of nutrient release of WLFZ in restoration work.