Low Permeability Sandstone Core Research Articles

Enhanced oil recovery and carbon sequestration in low-permeability reservoirs: Comparative analysis of CO2 and oil-based CO2 foam

Excessive CO2 emissions contribute to global climate change thus mandating effective methods for CO2 utilization and sequestering. In this study, one-dimensional flow simulation experiments on CO2 flooding, CO2 Huff-n-Puff, oil-based CO2 foam flooding, and oil-based CO2 foam Huff-n-Puff are conducted using low-permeability sandstone cores modeled after the Q131 block in Liaohe Oilfield, characterized by porosity ranging from 15% to 20% and permeability between 25 mD to 35 mD. Low permeability reservoirs are rich in oil resources and may effectively sequester CO2. Parameters pertaining to oil and gas production and carbon storage are collected. Nuclear magnetic resonance (NMR) is employed to determine the spatial variation of oil saturation in the cores. The experimental results show 8.03% and 41.21% increase in oil recovery factor by foam flooding and foam Huff-n-Puff relative to CO2 as the recovery agent. Moreover, NMR analysis confirms lower residual oil saturation in core samples using foam, suggesting better displacement agent. Oil-based CO2 foam recovery contributed to effective carbon sequestration, with carbon storage increasing by 34.24% and 315% relative to CO2 flooding and CO2 Huff-n-Puff, respectively. CO2 storage mechanisms for oil-based CO2 foam recovery method are detailed.

Study of the Seepage Mechanism in Thick Heterogeneous Gas Reservoirs

The seepage mechanism plays a crucial role in low-permeability gas reservoirs. Compared with conventional gas reservoirs, low-permeability sandstone gas reservoirs are characterized by low porosity, low permeability, strong heterogeneity, and high water saturation. Moreover, their percolation mechanisms are more complex. The present work describes a series of experiments conducted considering low-permeability sandstone cores under pressure-depletion conditions (from the Xihu Depression in the East China Sea Basin). It is shown that the threshold pressure gradient of a low-permeability gas reservoir in thick layers is positively correlated with water saturation and negatively correlated with permeability and porosity. The reservoir stress sensitivity is related to permeability and rock composition. Stress sensitivity is generally low when permeability is high or in the early stage of gas reservoir development. It is also shown that in sand conglomerates, especially the more sparsely filled parts, the interstitial materials among the conglomerates can be rapidly dislodged from the skeleton particles under stress. This material can therefore disperse, migrate, and block the pore throat producing serious, stress-sensitive damage.

Analysis on the mechanism and characteristics of nanofluid imbibition in low permeability sandstone core pore surface: Application in reservoir development engineering

In this work, the mechanism of nanofluid imbibition in the development of low permeability reservoirs is studied. Firstly, by analyzing nuclear magnetic resonance (NMR) curves and imaging maps, the imbibition displacement effects of low-permeability reservoirs in water and different nanofluids are compared. Subsequently, the influence characteristics of rock modification mechanism of nanofluid on imbibition displacement are analyzed by three-phase contact angle experiments. Finally, the attraction forces between oil and rock surfaces with different properties are measured by atomic force microscopy (AFM) experiments, and the influence of wetting inversion of nanofluids on the adsorption between oil and reservoir rocks is evaluated. The results show that the relaxation time map area of the core treated with nanofluid is smaller than that of the core treated with water, and the NMR images show that the nanofluid has a higher sweep efficiency, indicating that nanofluid can improve the oil displacement efficiency of low-permeability reservoirs. The higher the nanoparticle concentration of fluid, the more significant the effect. In addition, the effect of nanofluids on oil displacement efficiency in small pores and large pores of the reservoir is obvious, and the increase amplitude is 30 % and 50 %, respectively. Scanning electron microscope (SEM) images show that nanoparticles adsorbed on the reservoir inner wall exert a wetting inversion effect, leading to changes in reservoir wettability and promoting imbibition oil displacement, which is also reflected in the NMR maps. Contact angle experiments show that nanofluids convert the lipophilicity of rock surface into hydrophilicity, and the contact area between oil and rock shrinks due to the change of wettability and the decrease of interface energy, which weakens the adsorption between the two, promotes capillary imbibition of fluid and oil displacement. The AFM experiment confirms that nanoparticles reduce the microscopic adsorption force between oil and rock through wetting inversion and interface energy reduction. It is less difficult for the fluid to peel oil from the reservoir rock, which promotes the oil displacement. The studies show that nanofluid imbibition has advantages in the field of low permeability reservoir development.

Optimization and performance evaluation of a novel anhydrous CO2 fracturing fluid

The conventional water-based fracturing fluids have such defects as large water consumption, serious environmental pollution and water-sensitive damage to reservoirs in the development of tight oil. In this study, a novel anhydrous CO2 fracturing fluid system was constructed with the compositions of 7 wt% polydimethylsiloxane (100 cs), 5 wt% ethanol and 88 wt% liquid CO2. The viscosity of the system could reach 6.52 mPa s, which was 37 times higher than that of pure liquid CO2 at −15 °C and 30 MPa. The pressure resistance, temperature resistance, anti-swelling property, filtration loss property, core damage property, corrosion property and wetting inversion property of anhydrous CO2 fracturing fluid were systematically evaluated by physical simulation experiments. The environmental scanning electron microscopy (ESEM) and mercury injection experiment were conducted. The viscosity retention rate of anhydrous CO2 fracturing fluid reaches 47.92% when the temperature increases by 50 °C. When the pressure increases by 25 MPa, the viscosity increases by 2.6 times. It ensures that the viscosity of anhydrous CO2 fracturing fluid is well retained after injection into the formation. In addition, the anti-swelling rate of anhydrous CO2 fracturing fluid reaches 90.91%. The filtration coefficient is reduced by 69.20%. For low permeability sandstone cores, the permeability damage rate is 18.80% and the porosity damage rate is 12.58%. After aging for 30 h, the permeability and porosity of core increased 39.23% and 5.52%, respectively. Meanwhile, the wettability of the core could be changed from hydrophilic to neutral, which reduced the flow resistance of the oil phase and improved tight oil recovery. Through this study, we hope to broaden the application of anhydrous CO2 fracturing fluids in tight oil development.

Experimental investigation on the mechanism of low permeability natural gas extraction accompanied by carbon dioxide sequestration

The injection of CO2 into natural gas reservoir is regarded can increase natural gas recovery accompanied with CO2 sequestration. In this work, we first demonstrated that the gas adsorption ability in the sampled plunger low permeability sandstone core was only about 1/10 of that in the core powders, the former was more representative for use. The existence of bound water substantially weakened the gas adsorption in the core. The CO2 diffusion coefficients in low permeability cores were in the order of 10−8-10−9 m2/s, which increased with decreasing pressure but dramatically decreased with the existence of bound water. Last, long core experiments for natural gas recovery through CO2 flooding showed that the CO2 injection substantially increased the natural gas recovery ratio R. And we for the first time demonstrated that due to the higher CO2 density than that of natural gas through experiments, the CO2 injection at the relative low position showed higher R than that at the high injection position. And with the highest CO2 sequestration amount (M) reached 64.36 kg/m3. The injection of CO2 into low permeability natural gas reservoir to realize both natural gas recovery and CO2 sequestration are tested feasible and effective.

Experimental investigation on reservoir damage caused by clay minerals after water injection in low permeability sandstone reservoirs

Water injection is an effective method for developing low permeability sandstone reservoirs. In the process of water flooding, reservoir damage can occur due to clay mineral content changes and it will significantly affect oil production. There are few investigations on the changes in clay mineral content and the degree of reservoir damage after injecting the water into low permeability sandstone reservoirs with different permeabilities and lithologies. In this study, low permeability natural cores from different lithological strata were collected from 4 wells in the Daqing sandstone reservoir, and clay mineral components and contents were measured through X-ray diffraction. Changes in the clay mineral content were determined after water injection. The reservoir damage mechanism by clay mineral migration was determined by analyzing scanning electron microscopy (SEM) images after water injection. Meanwhile, the porosity and permeability of the cores were tested after water injection, and the degree of reservoir damage in different lithological strata was determined. The clay mineral content ranges from 6.78 to 14.14% in low permeability sandstone cores and declines by 49.73% after water flooding. Illite, chlorite and illite/smectite mostly decrease, and kaolinite decreases the least. Due to the large particle size of kaolinite, kaolinite migration will block the pore-throats and cause formation damage after water flooding. In argillaceous siltstone and siltstone, kaolinite particles blocking pore-throats are very serious, and the permeability decreases greatly by 21.87–36.89% after water injection. With increasing permeability, the permeability decreases greatly after water injection. The findings of this study can help to better understand the mechanisms of formation damage after injecting water into low permeability sandstone reservoirs.

INFERRING CAPILLARY PRESSURE CURVE FROM 2D ROCK IMAGES BASED ON FRACTAL THEORY IN LOW-PERMEABILITY SANDSTONE: A NEW INTEGRATED APPROACH

Reliable capillary pressure data are required for reservoir simulation and fluid flow characterization in porous media. The capillary pressure is commonly measured in the laboratory, which is costly, challenging, and accompanied by measurement uncertainties, especially for low-permeability core samples. Besides laboratory measurements, two-dimensional (2D) rock images reveal another prospect to obtain capillary pressure curves. This paper presents a new integrated approach combining image processing and fractal theory to infer the capillary pressure curve from 2D rock images in low-permeability sandstone. Our approach’s unique feature is its new representation of the pore structure based on information extracted from 2D cross-sections using image processing techniques (i.e. image segmentation and watershed partitioning). Furthermore, we derived an innovative analytical fractal model to calculate the capillary pressure from the newly proposed pore system representation. A new tortuous length equation is introduced to eliminate the developed fractal models’ dependency on the straight capillary length. The pore fractal dimension is computed using the box-counting method from the processed 2D image. The tortuosity fractal dimension is obtained from solving the developed fractal equations of porosity and permeability with the corresponding laboratory measurements. Additionally, a procedure for inferring capillary pressure from multiple cross-sections is proposed. The good accuracy in predicting capillary pressure for five low-permeability sandstone core samples demonstrates the developed approach’s robustness.

Effect of Injection Pressure on CO2 Huff-n-Puff in Low-Permeability Sandstone Cores Using Nuclear Magnetic Resonance

In order to figure out the micro-scale recovery degree of different pore sizes, the T2 spectrum of low-permeability sandstone cores before and after CO2 huff-n-puff is obtained using NMR technique. The results show that the micro-scale recovery degree increases with increase of pore sizes. Oil in macropores and medium pores is more easily produced, and Oil in micropores is difficult to recover at 7-12MPa. The total recovery degree of three cores increases with the increase of injection pressure. This study is expected to be significant for understanding the mechanisms of CO2 huff-n-puff for enhancing oil recovery in low-permeability sandstone reservoirs.

Experimental Investigation of Permeability Evolution on Sandstone in Triaxial and Long-Term Dissolution Experiment

The temporal permeability and damage evolutions of low-permeability sandstone cores during triaxial and long-term dissolution experiments were measured using a triaxial-flow system. Three triaxial experiments were performed on sandstone cores having initial permeability ranging from 78 × 10 − 18 m 2 to 120 × 10 − 18 m 2 . Two sets of long-term dissolution experiments were conducted on cracked sandstone cores. All dissolution experiments were performed at room temperature and using a 10 g/L H2SO4 and 0.2 g/L H2O2 input solution. Permeability evolution was determined using Darcy’s law. The cores experienced an average increase of 25% in permeability in the dissolution experiment and 900%~1500% increase at the end of the experiment. The dissolution was fairly homogeneous during the long-term experiments whether on the 1 mm scale or the 10 μm scale. The relationship between damage and permeability was speculated and its correlation coefficient has been proved to be close to 1. These results suggest that hydraulic fracturing works well in permeability increase in low-permeability sandstone reservoir.

Experimental Investigation of Hydrophobically Modified α-ZrP Nanosheets for Enhancing Oil Recovery in Low-Permeability Sandstone Cores.

Highly crystalline α-zirconium phosphate (α-ZrP) nanoparticles were synthesized and exfoliated into nanosheets, and then the hydrophilic nanosheets were modified into hydrophobic nanosheets with octadecyltrichlorosilane (OTS). Scanning electron microscopy, Fourier transform infrared spectroscopy, X-ray diffraction, and thermogravimetric analysis were applied to confirm the morphology and chemical structure of the nanosheets. Contact angle measurement was conducted to explore the wettability alteration of the hydrophobically modified α-ZrP nanosheets, and the result showed that the wettability of the core was changed into hydrophobicity. When ZrP–OTS nanosheets were injected during water-flooding, a Pickering emulsion will be formed. The droplet diameters and viscosities of the Pickering emulsions were measured. The hydrophobically modified α-ZrP nanosheets were applied in low-permeability sandstone cores and various concentrations were tested. The injectivity of the hydrophobically modified α-ZrP nanosheets was also studied and the result indicated that the nanosheets exhibit good injectivity. The mechanisms for enhancing oil recovery by utilizing hydrophobic α-ZrP nanosheets were analyzed: forming Pickering emulsions and increasing the viscosity of the displacing phase. Forming emulsions and increasing the viscosity of the flooding phase can enhance the microdisplacement efficiency, while good injectivity can also enhance the macrodisplacement efficiency. The result indicated the possibility of using hydrophobically modified α-ZrP nanosheets for enhancing oil recovery in a low-permeability reservoir.

Silica-based amphiphilic Janus nanofluid with improved interfacial properties for enhanced oil recovery

Silica-based amphiphilic Janus nanoparticles were synthesized for application in the field of enhanced oil recovery. The organic hydrophobic chain was grafted onto the SiO2 nanoparticles using a Pickering emulsion method. The chemical structure of the synthesized Janus nanoparticles was then characterized by TEM and FT-IR. Their interfacial properties were systematically investigated in terms of interfacial tension, contact angle and interfacial viscosity. The obtained results showed that the oil-water interfacial tension was reduced down to 2.28 mN/m when the concentration of the Janus nanoparticles is 0.05 wt%. Moreover, the Janus nanofluids could effectively alter the wettability of the rock from oil-wet to water-wet. The displacement experiments with low-permeability sandstone cores indicated that up to 15.74% increments of the oil recovery can be obtained by injecting 100 mg/L Janus nanofluids. Attributing to their hydrophilic-lipophilic balance properties, the Janus nanoparticles can quickly transport to the oil-water interface; consequently, a stable interfacial film which is beneficial to enhance oil recovery will form at the oil-water interface. Thus, the synthesized Janus nanoparticles could serve as an ideal candidate for enhanced oil recovery.

An experimental feasibility study on the use of CO2-soluble polyfluoroacrylates for CO2 mobility and conformance control applications

High molecular weight polyfluoroacrylate (PFA) is an amorphous, sticky, hydrophobic, oil-phobic, CO2-soluble homopolymer. 1 wt% PFA-in-CO2 solutions are four times as viscous as pure CO2. Although these solutions provided modest mobility control, unexpectedly large increases in pressure drop occurred because a portion of the PFA adsorbed onto the pore surfaces, altering wettability and significantly permeability. Further, PFA exhibited diminished solubility in CO2 in the presence of light extracted hydrocarbons. Although these effects rendered CO2-PFA solutions inappropriate for mobility control, excellent conformance control for dual parallel brine-saturated cores was attained when a CO2-PFA solution was first injected into the isolated high permeability sandstone core. This core was then placed in parallel with a low permeability sandstone core, and all of the subsequently injected CO2 was diverted to the low permeability core. Conformance control was not as effective in limestone, possibly due the low pH-induced erosion of the limestone that mitigated PFA adsorption.

A new model of pore structure typing based on fractal geometry

Abstract In this study, we report a physics-based model for pore structure typing in which a generalized model is also derived to calculate the specific surface area of the grains. In this model, a new pore-structure-type indicator is defined to characterize the discrepancies of pore structures based on the fractal geometry theory and a modified Kozeny-Carman equation. We compared the proposed model with the conventional model by comprehensive experimental tests in 130 low permeability sandstone cores from the Dongfang gas reservoir in the South China Sea. The fractal dimension of the grain Dg was first accurately calculated through thin section analysis. The results show that grains of low-permeability sandstone indeed have the bifractal distribution with constant radius boundaries of approximately 30 μm, potentially accounting for the multiscale of pore spaces. Compared with the conventional model, considering the complex pore and grain size distributions as well as irreducible water saturation, the developed model as a generalized expression performs better in pore structure typing with higher correlation coefficients in porosity-permeability and structural coefficients-pore radius relationships due to the newly identified indicator with a wider range. Finally, a multiscale workflow was proposed to analyze the petrological and structural features of pore structures by two-dimensional core images, thin sections, scanning electron microscope, mercury intrusion tests and three-dimensional micro-computed tomography. This work enables us to explain the genetic types and differences of the pore structure and may help to characterize the internal connection of the grain structure-pore structure-flow mechanism in hydrocarbon exploration and development.

The Visual and Quantitative Study of the Microoccurrence of Irreducible Water at the Pore and Throat System in a Low-Permeability Sandstone Reservoir by Using Microcomputerized Tomography

The microflow equipment monitored with micro X-ray computerized tomography (CT) is employed to investigate the microoccurrence of the irreducible water in a low-permeability sandstone core. By means of image segmentation and the three-dimensional (3D) image reconstruction technique, the visual microdistribution characteristics of irreducible water in two-dimensional (2D) slices and the 3D pore-throat system are quantitatively evaluated. Some interesting findings are list as below. Firstly, due to the variant micro geometric structures of the pore-throat systems, specific core slices showed significantly different irreducible water saturation even though these slices had same areal porosity. Secondly, due to the influence of capillary trapping and the existence of oil-wetting clay (main chlorite), the irreducible water saturation in the throat system (64%) is much larger than that in the pore system (36%). Furthermore, the wetting phase (irreducible water) did not spread all over the surface of the pore-throat network which caused a much more complicated oil-water two-phase interface. Thirdly, in micro scale, the main irreducible water occurrence mode in the pore system is much different from that in the throat system. In the pore system, the irreducible water principally existed in the corner of the pores which are linked through a water film. While in the throat system, the irreducible water occurrence is dominated by the water film. However, 25.5% of the throats are blocked by the irreducible water which cut off the crude oil drainage channels.

Effect of CH4 on the CO2 breakthrough pressure and permeability of partially saturated low-permeability sandstone in the Ordos Basin, China

The behavior of CO2 that coexists with CH4 and the effect of CH4 on the CO2 stream need to be deeply analyzed and studied, especially in the presence of water. Our previous studies investigated the breakthrough pressure and permeability of pure CO2 in five partially saturated low-permeability sandstone core samples from the Ordos Basin, and we concluded that rocks with a small pore size and low permeability show considerable sealing capacity even under unsaturated conditions. In this paper, we selected three of these samples for CO2-CH4 gas-mixture breakthrough experiments under various degrees of water saturation. The breakthrough experiments were performed by increasing the gas pressure step by step until breakthrough occurred. Then, the effluent gas mixture was collected for chromatographic partitioning analysis. The results indicate that CH4 significantly affects the breakthrough pressure and permeability of CO2. The presence of CH4 in the gas mixture increases the interfacial tension and, thus, the breakthrough pressure. Therefore, the injected gas mixture that contains the highest (lowest) mole fraction of CH4 results in the largest (smallest) breakthrough pressure. The permeability of the gas mixture is greater than that for pure CO2 because of CH4, and the effective permeability decreases with increased breakthrough pressure. Chromatographic partitioning of the effluent mixture gases indicates that CH4 breaks through ahead of CO2 as a result of its weaker solubility in water. Correlations are established between (1) the breakthrough pressure and water saturation, (2) the effective permeability and water saturation, (3) the breakthrough pressure and effective permeability, and (4) the mole fraction of CO2/CH4 in the effluent mixture gases and water saturation. These results deepen our understanding of the multi-phase flow behavior in the porous media under unsaturated conditions, which have implications for formulating emergency response plans for gas leakage into unsaturated zones. Finally, knowing the flow characteristic of gas mixture can guide CO2 storage, CO2-EOR and CO2-ECBM projects. Future studies should pay attention to the effects of saline water with different salt types and concentrations on the multi-phase flow behavior with applications to geological CO2 storage and energy storage using CH4.

Comparison of Acidizing and Ultrasonic Waves, and Their Synergetic Effect for the Mitigation of Inorganic Plugs

The oil and gas industry is plagued by inevitable formation damaged in the wellbore proximity during entire life of the well. Therefore, it is indispensable to ameliorate the damaged permeability by either using conventional applied techniques or ultrasonic-assisted stimulation method. The latter is characterized by efficient, simple and convenient, and environmentally secure method. Due to these distinguished characteristics, the demand of this physical Enhanced Oil Recovery (EOR) technique increased in petroleum industry. In this study, ultrasonic waves and hydrochloric acid (HCl) were used separately as well as in combination to recover the lost productivity caused by calcium carbonate (CaCO3) inorganic plugs in low permeability sandstone core samples. Results showed that permeability recovery increased with irradiation time up to 100 min; however, it decreased with further irradiation. This deviation could be due to particles bridge formation at later stage. In addition, optimum frequency and power of...

Effect of Acoustic Stimulation on Aqueous Phase Trapping in Low-Permeability Sandstones

Formation damage from aqueous phase trapping in low-permeability sandstones can be removed using mutual solvents, blends of alcohols and mutual solvents, and surfactants. These treatments modify the interfacial tension of the trapped fluids or the wettability of the formation. However, treatments intended to remove a certain type of damage may cause other types of formation damage due to incompatibility with the rock and formation fluids. High-frequency acoustic waves have been used in industrial applications to clean up and remove contaminants. Important studies have been conducted to extend the use of acoustic waves for wellbore stimulation. This technical paper presents a laboratory investigation to determine the effects of ultrasonic (UT) treatment on interfacial tension and wettability alteration during invasion of fracturing fluids treated with surfactants in low-permeability sandstones. An experimental program consisting of a series of spontaneous imbibition experiments was conducted to measure the spontaneous imbibition potential of sandstone rock cores treated with surfactants in the presence of UT energy. Spontaneous imbibition tests were conducted in two steps. In the first, spontaneous imbibition tests were conducted on untreated low-permeability sandstone core samples in the presence of UT radiation. In the second step, spontaneous imbibition tests were conducted on cores flooded with surfactant while exposing the core to UT radiation from an acoustic horn. In each series experiments, the power output was changed to monitor the effect of acoustic power on wettability alteration. Results obtained from the experiments showed that acoustic stimulation improves imbibition of water in both water wet and intermediate wet cores. Wettability alteration is attributed to enhancement of capillary forces in water wet cores. For cores treated with water repelling surfactants, improvement in imbibition is attributed to detachment of surfactant molecules from the pore walls due to acoustic streaming of sonic waves. This research was originally intended to investigate removal of trapped water from fluid injection of low-permeability sandstones by acoustic stimulation. However, the obtained results show that it is possible to improve the recovery of trapped hydrocarbon in low-permeability sandstones under the influence of acoustic stimulation.

Static adsorption and dynamic retention of an anti‐salinity polymer in low permeability sandstone core

ABSTRACTThe technical viability of enhancing oil recovery (EOR) using polymer flooding has been verified. Through correcting the unfavorable mobility ratio, polymer flooding could significantly improve the macroscopic sweep efficiency of waterflooding, which makes it attractive in middle to high permeability reservoirs. However, as the depletion of these easy‐to‐produce resources, the interests of oil industry will be diverted to low permeability reservoirs and polymer flooding is believed to be one of the key methods for this type of reservoir. To meet this technological tendency, the current work investigated the applicability of an anti‐salinity polymer (KYPAM) in low permeability sandstone reservoirs. The interactions between polymer and sandstone surface including static adsorption and dynamic retention were addressed. Static adsorption data proved that the adsorptive behavior of this anti‐salinity polymer was closely related to molecular weight and concentration. The quantity of the detained KYPAM polymer in the sandstone core rapidly increased once the permeability dropped below 38 mD. High molecular weight KYPAM experienced noticeable retention compared with low molecular weight polymers resulting from the large hydrodynamic size. Due to polymer retention, the permeability of the sandstone core was significantly influenced particularly for the low permeability cores. © 2016 Wiley Periodicals, Inc. J. Appl. Polym. Sci. 2017, 134, 44487.

Foam Performance in Low Permeability Laminated Sandstones

Most studies on foam are related to homogeneous and highly permeable porous media. As the reservoir situation is rather heterogeneous with respect to permeability and layering, foam properties in layered porous media with lower permeabilities are also important to understand. This study investigates foam behavior and performance in naturally laminated sandstone cores. Laminations are common constituents in sandstone petroleum reservoirs where they usually occur as thin deformed layers in the host formation. Evidences of rock heterogeneity were confirmed by several different analyses on laminated material. From image processing of thin sections and 2D X-ray experiments, the laminas present were found to exhibit both lower porosity and permeability than the host rock, and also shown to form barriers to fluid flow. Foam experiments were performed in three low permeability sandstone cores with relative similar permeability but with a different degree of laminated stratifications parallel to flow direction. Foam was generated in all the low permeability laminated cores. However, the degree of lamina in each core influenced foam performance significantly, reflected by large variations in mobility reduction factors (MRF ∼ 20–500) and foam breakthrough times. Increased lamination resulted in weaker foams and earlier foam breakthroughs. One explanation to this could be that the low permeability laminas introduce different degrees of discontinuities and compartmentalization to foam flow. Findings in our study indicate that foam properties and performance can be strongly influenced by local heterogeneities, such as laminations naturally found in many sandstone reservoirs.

Dynamic displacement and non-equilibrium dissolution of supercritical CO2 in low-permeability sandstone: An experimental study

An experimental setup was developed for conducting core-flood experiments of supercritical CO2 and water under pressures higher than 8.00MPa and a temperature of 40°C. Two representative low-permeability sandstone cores were obtained from the Shenhua Group CCS site in the Erdos Basin in China and the experimental study was in support of China's first field test. Unlike most laboratory experiments with two-phase CO2–water flow, dry CO2 was injected in the CO2-flood experiments, and deionized water (without dissolved CO2) was used in the water-flood experiments. In the CO2-flood experiments, dynamic displacement of water by injected CO2 was investigated using transient inlet and outlet pressures and transient flow rates of outflowing CO2 and water. The residual water saturation estimated at the end of the experiments (with an injection rate of 1.2mLmin−1) for both cores is 0.52. The higher residual water saturation can be attributed to the high CO2/water viscosity contrast and non-uniform displacement. The estimated relative CO2 permeability at residual water saturation varies from 0.13 to 0.23. During the water-flood experiments, non-equilibrium CO2 dissolution at the core scale was observed using the transient concentration of total dissolved CO2 in outflowing water. The non-equilibrium dissolution possibly results from non-uniform distribution of water and CO2 caused by sub-core heterogeneity. The endpoint CO2 saturation estimated varies from 0.17 to 0.10 for a low injection rate of 0.2mLmin−1. Additional experiments indicate that higher water injection rate (up to 2mLmin−1) drive more free-phase CO2 out of the cores, with less CO2 mass stored, because of CO2 density change with elevated pressure and weaker capillarity for low-permeability sandstone. Additional experiments with injected water of varying dissolved CO2 concentration (including CO2-saturated conditions) indicate that CO2 dissolution mobilizes additional free-phase CO2 out of the cores by enhanced displacement, and increases relative water permeability after CO2 displacement is complete, even though dissolution only accounts for 6–7% of the total CO2 mass initially in the cores before the experiments.