Application of foam assisted water-alternating-gas flooding and quantification of resistivity and water saturation by experiment and simulation to determine foam propagation in sandstone

Foam flooding by Foam Assisted Water-Alternating-Gas (FAWAG) is an important enhanced oil recovery method that has proven successful in experimental and pilot studies. The present study is carried out to monitor the movement of the foam front once injected into the porous medium. This study aims to investigate applications of resistivity waves to monitor foam propagation in a sandstone formation. In the present lab-scale experiments and simulations, resistivity measurements were carried out to monitor the progression of foam in a sand pack, and the relationships between foam injection time and resistivity, as well as brine saturation, were studied. The brine saturation from foam simulation using CMG STAR is exported to COMSOL and calculated true formation resistivity. A diagram was produced summarizing the progression of foam through the sand pack in the function of time, which enabled us to establish how foam progressed through a porous medium. A surfactant and brine mixture was injected into the sand pack, followed by nitrogen gas to generate the foam in situ. As foam progressed through the sand pack, resistance measurements were taken in three zones of the sand pack. The resistance was then converted into resistivity and finally into brine saturation. As foam travels through the sand pack, it is predicted to displace the brine initially in place. This gradually increases each zone's resistivity (decreases the brine saturation) by displacing the brine. Also, an increase in the surfactant concentration results in higher resistivity. Finally, a comparison of three different surfactant concentrations was evaluated in terms of resistivity results, water saturation, and foam propagation monitoring to obtain the optimum surfactant concentration involved in foam flooding.

Impact of Methylene Blue on Enhancing the Hydrocarbon Potential of Early Cambrian Khewra Sandstone Formation from the Potwar Basin, Pakistan

Significant amounts of hydrocarbon resources are left behind after primary and secondary recovery processes, necessitating the application of enhanced oil recovery (EOR) techniques for improving the recovery of trapped oil from subsurface formations. In this respect, the wettability of the rock is crucial in assessing the recovery and sweep efficiency of trapped oil. The subsurface reservoirs are inherently contaminated with organic acids, which renders them hydrophobic. Recent research has revealed the significant impacts of nanofluids, surfactants, and methyl orange on altering the wettability of organic-acid-contaminated subsurface formations into the water-wet state. This suggests that the toxic dye methylene blue (MB), which is presently disposed of in huge quantities and contaminates subsurface waters, could be used in EOR. However, the mechanisms behind hydrocarbon recovery using MB solution for attaining hydrophilic conditions are not fully understood. Therefore, the present work examines the impacts of MB on the wettability reversal of organic-acid-contaminated Khewra sandstone samples (obtained from the outcrop in the Potwar Basin, Pakistan) under the downhole temperature and pressure conditions. The sandstone samples are prepared by aging with 10-2 mol/L stearic acid and subsequently treated with various amounts of aqueous MB (10-100 mg/L) for 1 week. Contact angle measurements are then conducted under various physio-thermal conditions (0.1-20 MPa, 25-50 °C, and salinities of 0.1-0.3 M). The results indicate that the Khewra sandstone samples become hydrophobic in the presence of organic acid and under increased pressure, temperature, and salinity. However, the wettability changes from oil-wet to preferentially water-wet in the presence of various MB solutions, thus highlighting the favorable effects of MB on EOR from the Khewra sandstone formation. Moreover, the most significant change in wettability is observed for the Khewra sandstone sample that was aged using 100 mg/L MB. These results suggest that injecting MB into deep underground Khewra sandstone reservoirs may produce more residual hydrocarbons.

Strain measurement with multiplexed FBG sensor arrays: An experimental investigation

In conventional rock mechanics testing, radial strain measuring devices are usually attached to the sample's surface at its mid-height. Although this procedure provides a realistic picture of the lateral deformation undergone by homogeneous samples, however, this assumption may not be accurate if the tested rock has significant heterogeneity. Fibre Bragg Grating (FBG) sensors have recently been introduced to various rock testing applications due to their versatility over conventional strain gauges and radial cantilevers. FBG sensors have small size, multiplexing capability, and immunity to magnetic interference. The main objective of this study is to explore and understand the capabilities of FBG sensing for strain measurement during rock mechanics testing, including under confining. To do so, two limestone plugs (Savonnières limestone) and one acrylic Poly Methyl Methacrylate (PMMA) plug, all of 38 mm diameter, were prepared. The acrylic plug and one of the Savonnières samples plugs were subjected to Unconfined Compressive Strength (UCS) tests. The second Savonnières plug was subjected to a hydrostatic test up to 20 MPa confining at room temperature. FBG sensors of 125 μm cladding diameter with ceramics (Ormocer) coating were glued on the surface of each sample, spreading across the entire sample's height. Strain gauges and cantilever-type radial gauges were used on the samples submitted to UCS for comparison. Results show that radial strain measurements and calculated elastic properties derived from the FBG readings for samples are comparable to readings from the conventional strain gauges and cantilever-type devices. Apparent bulk moduli based on volumetric strain computed from FBG radial strain readings during the hydrostatic test on the Savonnières sample was consistent with benchtop measurements conducted on the Savonnières sample and another plug extracted from the same parental block, as well as published literature data. Moreover, variations in the calculated elastic properties are interpreted as evidence that the FBG sensors detected heterogeneities in the samples' inner structure, which can be seen in the density profiles computed from x-ray CT images. Such observation confirms the potential of the presented FBG sensors configuration for 3D strain mapping in rock mechanics tests.

An experimental workflow to assess the applicability of microemulsions for conformance improvement in oil-bearing reservoir

A comprehensive workflow approach is necessary to link multiple experimental tasks and identify microemulsion (ME) formulations with 'optimal' stability, displacement behavior and technical feasibility in the petroleum industry. In this paper, a systematic approach is described with the aid of a case study which involves the formulation of an anionic sodium dodecyl sulfate-based microemulsion. The design of such ME systems requires a proper methodology, substantial laboratory work, and functional assessment from research/industrial viewpoints. The surfactant has been screened in terms of its micellization potential, followed by phase behavior analysis and Winsor classification of prepared microemulsions. The desired composition(s) are characterized via several tools to determine droplet size, morphology, oil/water solubilization potentials and salinity scan results. The suitability of the microemulsion system for conformance improvement technology (CIT) is proposed to be assessed via physicochemical evaluation studies encompassing two attributes: rheology and stability. For a favorable 'conforming' drive, the microemulsion must exhibit phase stability, sufficient injectivity, and moderate-to-high viscosity under shear. Technical assessment by the industry and research team must also include factors related to cost, availability of chemicals, environmental degradation, and reservoir considerations. The article demonstrates a comprehensive all-inclusive workflow methodology to design and formulate surfactant-stabilized microemulsions via case study analysis for application in CIT. This represents a sound approach to identifying efficient, cost-effective injection fluid systems and provides a framework to identify useful parameters for ME formulation design and employ the proposed (effective) strategy for conformance control.

Enhancing the CO2 trapping capacity of Saudi Arabian basalt via nanofluid treatment: Implications for CO2 geo-storage

Mineralization reactions in basaltic formations have gained recent interest as an effective method for CO₂ geo-storage in order to mitigate anthropogenic greenhouse gas emissions. The CO₂/rock interactions, including interfacial tension and wettability, are crucial factors in determining the CO₂ trapping capacity and the feasibility of CO₂ geological storage in these formations. The Red Sea geological coast in Saudi Arabia has many basaltic formations, and their wetting characteristics are rarely reported in the literature. Moreover, organic acid contamination is inherent in geo-storage formations and significantly impacts their CO₂ geo-storage capacities. Hence, to reverse the organic effect, the influence of various SiO₂ nanofluid concentrations (0.05-0.75 wt%) on the CO₂-wettability of organic-acid aged Saudi Arabian (SA) basalt is evaluated herein at 323 K and various pressures (0.1-20 MPa) via contact angle measurements. The SA basalt substrates are characterized via various techniques, including atomic force microscopy, energy dispersive spectroscopy, scanning electron microscopy, and others. In addition, the CO₂ column heights that correspond to the capillary entry pressure before and after nanofluid treatment are calculated. The results show that the organic acid-aged SA basalt substrates become intermediate-wet to CO₂-wet under reservoir pressure and temperature conditions. When treated with SiO₂ nanofluids, however, the SA basalt substrates become weakly water-wet, and the optimum performance is observed at an SiO₂ nanofluid concentration of 0.1 wt%. At 323 K and 20 MPa, the CO₂ column height corresponding to the capillary entry pressure increases from -957 m for the organic-aged SA basalt to 6253 m for the 0.1 wt% nano-treated SA basalt. The results suggest that the CO₂ containment security of organic-acid-contaminated SA basalt can be enhanced by SiO₂ nanofluid treatment. Thus, the results of this study may play a significant role in assessing the trapping of CO₂ in SA basaltic formations.

Influence of Henna Extracts on Static and Dynamic Adsorption of Sodium Dodecyl Sulfate and Residual Oil Recovery from Quartz Sand

The application of surfactant flooding for enhanced oil recovery (EOR) promotes hydrocarbon recovery through reduction of oil-water interfacial tension and alteration of oil-wet rock wettability into the water-wet state. Unfortunately, surfactant depletion in porous media, due to surfactant molecule adsorption and retention, adversely affects oil recovery, thus increasing the cost of the surfactant flooding process. Chemical-based materials are normally used as inhibitors or sacrificial agents to minimize surfactant adsorption, but they are quite expensive and not environmentally friendly. Plant-based materials (henna extracts) are far more sustainable because they are obtained from natural sources. However, there is limited research on the application of henna extracts as inhibitors to reduce dynamic adsorption of the surfactant in porous media and improve oil recovery from such media. Thus, henna extracts were introduced as an eco-friendly and low-cost sacrificial agent for minimizing the static and dynamic adsorption of sodium dodecyl sulfate (SDS) onto quartz sand in this study. Results showed that the extent of surfactant adsorption was inversely proportional to the henna extract concentration, and the adsorption of the henna extract onto the quartz surface was a multilayer adsorption that followed the Freundlich isotherm model. Precisely, the henna extract adsorption on quartz sand is in the range of 3.12-4.48 mg/g (for static adsorption) and 5.49-6.73 mg/g (for dynamic adsorption), whereas the SDS adsorption on quartz sand was obtained as 2.11 and 4.79 mg/g at static and dynamic conditions, respectively. In the presence of 8000 mg/L henna extract, SDS static and dynamic adsorption was significantly reduced by 64 and 82%, respectively. At the same conditions, the residual oil recovery increased by 9.2% over normal surfactant flooding. The study suggests that the use of henna extracts as a sacrificial agent during SDS flooding could result in the reduction of static and dynamic adsorption of surfactant molecules on quartz sand, thus promoting hydrocarbon recovery from sandstone formations.

Wettability of Nanostructured Transition-Metal Oxide (Al2O3, CeO2, and AlCeO3) Powder Surfaces

Wettability has been the focal point of many studies in metal oxide materials due to their applications in water-gas shift reactions, organic reactions, thermochemical water splitting, and photocatalysis. This paper presents the results of systematic experimental studies on the wettability of surfaces of nanostructured transition-metal oxides (TMOs) (Al₂O₃, CeO₂, and AlCeO₃). The wettability of nanoparticles was investigated by measuring contact angles of different concentrations of water-based nanofluids (0.05-0.1 wt%) on the glass slide. The morphology, the heterostructure, and the nature of incorporated nanoparticles were confirmed by scanning electron microscopy (SEM) and transmission electron microscopy (TEM). Characteristic diffraction patterns of the nanomaterials were evaluated using energy-dispersive X-ray spectroscopy (EDS) and X-ray diffraction (XRD) techniques. The contact angles of water-Al₂O₃, water-CeO₂, and water-AlCeO₃ were measured as 77.5 ± 5°, 89.8 ± 4°, and 69.2 ± 1°, respectively. This study suggests that AlCeO₃ is strongly water-wet (hydrophilic), while CeO₂ is weakly water-wet (hydrophobic). It further demonstrated that the sizes and compositions of the nanoparticles are key parameters that influence their wetting behaviors.

Influence of organic molecules on wetting characteristics of mica/H2/brine systems: Implications for hydrogen structural trapping capacities

HYPOTHESIS

Actualization of the hydrogen (H₂) economy and decarbonization goals can be achieved with feasible large-scale H₂ geo-storage. Geological formations are heterogeneous, and their wetting characteristics play a crucial role in the presence of H₂, which controls the pore-scale distribution of the fluids and sealing capacities of caprocks. Organic acids are readily available in geo-storage formations in minute quantities, but they highly tend to increase the hydrophobicity of storage formations. However, there is a paucity of data on the effects of organic acid concentrations and types on the H₂-wettability of caprock-representative minerals and their attendant structural trapping capacities.

EXPERIMENT

Geological formations contain organic acids in minute concentrations, with the alkyl chain length ranging from C₄ to C₂₆. To fully understand the wetting characteristics of H₂ in a natural geological picture, we aged mica mineral surfaces as a representative of the caprock in varying concentrations of organic molecules (with varying numbers of carbon atoms, lignoceric acid C₂₄, lauric acid C₁₂, and hexanoic acid C₆) for 7 days. To comprehend the wettability of the mica/H₂/brine system, we employed a contact-angle procedure similar to that in natural geo-storage environments (25, 15, and 0.1 MPa and 323 K).

FINDINGS

At the highest investigated pressure (25 MPa) and the highest concentration of lignoceric acid (10^-2 mol/L), the mica surface became completely H₂ wet with advancing (θ_a= 106.2°) and receding (θ_r=97.3°) contact angles. The order of increasing θ_a and θ_r with increasing organic acid contaminations is as follows: lignoceric acid > lauric acid > hexanoic acid. The results suggest that H₂ gas leakage through the caprock is possible in the presence of organic acids at higher physio-thermal conditions. The influence of organic contamination inherent at realistic geo-storage conditions should be considered to avoid the overprediction of structural trapping capacities and H₂ containment security.

Foaming properties, wettability alteration and interfacial tension reduction by saponin extracted from soapnut (Sapindus Mukorossi) at room and reservoir conditions

In this study, a natural surfactant, saponin was isolated from soapnut (Sapindus Mukorossi). The extracted surfactant was characterized by Fourier-transform infrared spectroscopy (FTIR) analysis. The effectiveness of the isolated surfactant as EOR agent was evaluated from foam generation/stabilization properties, wettability alteration of the rock surfaces, as well as oil-water interfacial tension (IFT) reduction characteristics. The performance of the extracted saponin was compared with that of a commercial saponin and sodium dodecyl sulfate (SDS). The foaming properties of the saponin with carbon dioxide (CO2) was characterized using Teclis Foamscan instrument at room condition and 60 °C. The IFT and contact angles at room conditions and reservoir conditions were measured using KRŰSS Drop Shape Analyzer (DSA 25 and DSA 100) via pendant drop and sessile drop techniques respectively. The foamability of the saponin-stabilized foam was good at ambient condition and 60 °C. Moreover, the time taken for almost 100% liquid drainage was higher in saponin-stabilized foam than the SDS-stabilized foam. The optimum concentration for attaining maximum foam stability decreased from 0.4 wt% at room temperature to 0.1 wt% at 60 °C. Signifying that the quantity of the surfactant to be used in foam generation could reduce at high temperature. The isolated saponin exhibited relatively good interfacial activities individually and in synergistic interaction with silicon dioxide (SiO2) nanoparticles at reservoir conditions. Precisely, at 8 MPa and 80 °C, the crude-oil water IFT was reduced from 23.24 mN/m to 1.59 mN/m (about 93.2%) by 0.2 wt% saponin concentration. The IFT was further reduced to 0.87 mN/m (about 96.3%) by a mixed system of 0.5 wt% saponin and 0.05 wt% SiO2 nanoparticles concentration. Increasing IFT with increasing temperature were observed at very high temperature due to phase separation resulting from clouding phenomenon. However, the clouding temperature increased with 0.1 wt% saponin concentration, and in presence of SiO2 nanoparticles (0.05 wt% and 0.1 wt%). The study suggests that the extracted saponin could be considered as supplementary alternative to conventional EOR surfactants.

Synergetic Effect of Surfactant Concentration, Salinity, and Pressure on Adsorbed Methane in Shale at Low Pressure: An Experimental and Modeling Study

The influence of an anionic surfactant, a cationic surfactant, and salinity on adsorbed methane (CH₄) in shale was assessed and modeled in a series of systematically designed experiments. Two cases were investigated. In case 1, the crushed Marcellus shale samples were allowed to react with anionic sodium dodecyl sulfate (SDS) and brine. In case 2, another set of crushed Marcellus shale samples were treated with cetyltrimethylammonium bromide (CTAB) and brine. The surfactant concentration and salinity of brine were varied following the Box-Behnken experimental design. CH₄ adsorption was then assessed volumetrically in the treated shale at varying pressures (1-50 bar) and a constant temperature of 30 °C using a pressure equilibrium cell. Mathematical analysis of the experimental data yielded two separate models, which expressed the amount of adsorbed CH₄ as a function of SDS/CTAB concentration, salinity, and pressure. In case 1, the highest amount of adsorbed CH₄ was about 1 mmol/g. Such an amount was achieved at 50 bar, provided that the SDS concentration is kept close to its critical micelle concentration (CMC), which is 0.2 wt %, and salinity is in the range of 0.1-20 ppt. However, in case 2, the maximum amount of adsorbed CH₄ was just 0.3 mmol/g. This value was obtained at 50 bar and high salinity (∼75 ppt) when the CTAB concentration was above the CMC (>0.029 wt %). The findings provide researchers with insights that can help in optimizing the ratio of salinity and surfactant concentration used in shale gas fracturing fluid.