Spontaneous Imbibition Experiments Research Articles

Influence of surfactants on wettability alteration during hydraulic fracturing in sandstone reservoirs: NMR analysis in spontaneous imbibition experiments

Influence of surfactants on wettability alteration during hydraulic fracturing in sandstone reservoirs: NMR analysis in spontaneous imbibition experiments

Spontaneous imbibition characteristics and influencing factors of shale oil reservoir in Qintong depression

This study integrates one-dimensional and two-dimensional nuclear magnetic resonance (NMR) techniques to conduct spontaneous imbibition experiments on two distinct lithologies (laminated calcareous shale and bulk clay-rich shale) from the Qintong Depression using four different fluid types. Field emission scanning electron microscopy (FE-SEM) and computed tomography (CT) scanning were employed to observe and track the dynamic changes in shale microstructures at specific intervals allowing for a comprehensive analysis of induced microfractures and their propagation patterns. These methods enabled a deeper understanding of the underlying mechanisms, enriching the interpretation of the imbibition results. The study reveals that anionic surfactants demonstrate exceptional performance during the imbibition process, and the combination of surfactants further enhanced oil recovery. The imbibition process can be divided into three stages: the imbibition diffusion stage, the transition stage, and the equilibrium stage, with the diffusion stage serving as the primary contributor, driven predominantly by capillary pressure. The calcareous shale cores exhibited the highest imbibition rates in the early stages, approaching equilibrium in the middle stages. Conversely, the clay-rich shale cores maintained relatively high imbibition rates throughout the second stage, indicating different imbibition dynamics based on lithology. NMR, CT scanning, and SEM analysis highlighted significant lithology-dependent differences in the mechanisms driving induced microfracture development during the imbibition and hydration. In laminated calcareous shale, imbibition and hydration primarily proceeded through the dissolution of calcareous minerals, resulting in pore expansion and induced microfractures along pre-existing fractures. In contrast, clay-rich shale exhibited similar mineral dissolution but also experienced clay swelling due to its high clay content, leading to the formation of bedding-parallel fractures with distinct directional patterns along weak mineral-matrix bonds. The experimental results underscored the pivotal role of lithology in determining final imbibition efficiency, with high-clay-content shales demonstrating superior recovery rates under spontaneous imbibition conditions. This study provides critical experimental data and insights into the microscopic mechanisms governing spontaneous imbibition across varied lithologies and fluid types in the Qintong Depression. The results offer foundational knowledge for optimizing oilfield development strategies.

Spontaneous imbibition of unsaturated sandstone under different vertical temperature gradients: neutron radiography experiments and dynamic models

To elucidate the imbibition behavior of water in complex temperature and stress environments, spontaneous imbibition experiments were conducted on unsaturated matrix sandstones at different vertical temperature gradients by neutron radiography technology. Additionally, corresponding dynamic models of water imbibition in porous media were established. The research results reveal the phased characteristics of sandstone spontaneous imbibition and the influence of vertical temperature gradient on the evolution of wetting front. Specifically, the initial development speed of the wetting front increases with an increase in the vertical temperature gradient, indicating a direct relationship. However, the growth rate of the wetting front gradually slows down with increasing time, eventually reaching a saturated state. Model validation demonstrates that the traditional Washburn's law is still valid in isothermal conditions without temperature gradient (G=0). Further analysis indicates that the imbibition rate has a direct correlation with linear thermal expansion coefficient (α) and viscosity temperature coefficient (β) across various vertical temperature gradients, and an inverse correlation with surface tension temperature coefficient (γ). Furthermore, when the values of α, β, and γ fall below 0.001, their impact on the imbibition rate becomes negligible. The sensitivity of the imbibition rate to parameters γ, β, and α decreases in that order, with γ being the most sensitive, followed by β, and α being the least sensitive. Moreover, the relative importance of α, β, and γ dictates their specific influence on the imbibition rate, and a synergistic effect exists among these parameters, which collectively influence the water absorption behavior of sandstone.

Comparative study on pore-connectivity and wettability characteristics of the fresh-water and saline lacustrine tuffaceous shales: triggering mechanisms and multi-scale models for differential reservoir-forming patterns

Although particular attention has been paid to responses of hydrocarbon storage and percolation capacity to the devitrification concerning lacustrine tuffaceous shale reservoirs in recent years, there is still a lack of systematical and comparative investigation on differential patterns and potential triggering mechanisms concerning development of the pore-microfracture systems and characteristics of surface wettability between the fresh-water and saline lacustrine settings, which is of considerable importance in fully understanding of genesis and spatial distribution of dessert reservoir intervals of tuffaceous shale reservoirs, and to provide further conceptual basis for deciphering shale-oil movability of saline lacustrine fine-grained mixed sedimentary sequences. In this study, tuffaceous shales from both the Upper Triassic Yanchang Formation in the Ordos Basin and Middle Permian Jingjingzigou Formation in the Junggar Basin are targeted to unravel the differential behavior of tuff devitrification and potential impacts on reservoir wettability and pore connectivity concerning fresh-water and saline lacustrine settings, and we present new results here from integrated analyses and combined interpretation of FE-SEM, Image Pro Plus (IPP) software image processing, contact angle and spontaneous imbibition experiments. In view of comparative analysis from representative samples, the tuffaceous shales from saline lacustrine environments are characterized by well-developed intergranular-intercrystalline and dissolution pores, and inorganic microfractures, generally yield a higher plane porosity of representative pore-fracture spaces and spontaneous imbibition slopes, a relatively lower average of n-decane contact angles and corresponding wettability parameters. The saline lacustrine tuffaceous shales are thus suspected to have undergone more intense devitrification resulting in a higher amount of devitrification and associated dissolution pores, and a relatively better connectivity between isolated micropore systems with adjacent microfractures. This would significantly facilitate the interface wettability reversal and occurrence of movable hydrocarbon fluid in microscopic reservoir spaces. Finally, a comprehensive and conceptual model is established illustrating the effects of differential devitrification on reservoir-forming patterns concerning tuffaceous shales developed in the fresh-water and saline lacustrine settings, respectively. These findings are of great theoretical and practical significance to enrich theory of high-quality reservoir formation and shale-oil accumulation in saline lacustrine tuffaceous shale reservoirs, and lay the foundation for guiding efficient exploration of continental fine-grained mixed sedimentary sequences.

The Role of Core Sample Geometry on Countercurrent Spontaneous Imbibition: Mathematical Foundation, Examples, and Experiments Accounting for Realistic Geometries

Summary Countercurrent spontaneous imbibition (SI) experiments are among the most common multiphase experiments performed on porous rock samples. Although the samples rarely are designed to give linear flow, they are often modeled and interpreted using mathematical descriptions assuming linear flow. In this work, the goal is to derive general understanding of how imbibition into different sample geometries behaves compared with linear (1D) imbibition. Using the mathematical theory of N-volume spheres (N being the dimension), we consider core samples as N-spherical and quantify their geometry by a dimension N and length scale L. For the special cases, N=1,2,3, we obtain linear, radial, and spherical flow; however, we treat the dimension as an arbitrary real number for cases not adhering to either of these regimes. Particularly, for rectangular or cylindrical core plugs, a continuous range of dimensions is produced. Theoretical calculations of N and L of arbitrary sample shapes are derived based on relations with area per volume and derivative of area with respect to volume. They correctly produce limit cases and physically meaningful values for symmetrical, cylindrical, and rectangular geometries. The differential equation for countercurrent imbibition in N-dimensions is derived and solved with numerical examples. Also, a simplified analytical solution assuming piston-like displacement is derived to get illustrative relations between system parameters (including dimension) and recovery and front position. Predicted recovery profiles of the N-dimensional (N-D) solution overlap consistently with numerical simulations (by an alternative simulator) into cylindrical geometries with a wide range of height/diameter ratios and viscosity ratios. At early time, the saturation profiles are self-similar (look the same plotted against position divided by square root of time) and identical regardless of dimension. As long as the profiles are self-similar near the open boundary, recovery is proportional to the square root of time. For N=1, this lasts long after the front has reached the closed boundary, while for N >1, it can happen long before the boundary has been reached. The same time scale was applicable for all geometries, stating especially that doubling the length scale increased the time of the entire recovery profile by a factor 4. As long as recovery is proportional to square root of time, at a given time, it is also proportional to dimension over length, NL, and the time needed to reach same level of recovery is proportional to LN2. Permeability anisotropy (lower vertical than horizontal permeability) could effectively be modeled using an effective increased height, which further was captured by the dimension and length scale. Literature and in-house experimental data were matched by the model and used to validate model predictions such as the variation in time, shape of recovery curves with changes in dimension, and the importance of accounting for the dimension (geometry) during data interpretation. The model is valid for all wetting states but assumes negligible gravity and compressibility effects.

Comparative study of nanoemulsion and micelle formed by surfactants containing benzene ring for spontaneous imbibition displacement

Nanoemulsion has a wide range of applications in oilfield chemistry due to its unique nanoscale size, excellent kinetic stability and high specific surface area. In this paper, a novel nanoemulsion oil flooding system was prepared using anionic surfactant sodium dodecyl benzene sulfonate (SDBS), the nonionic surfactant alkylphenol ethoxylates (OP-10), kerosene, n-butanol and deionized water. The particle size, Zeta potential, interfacial tension (IFT) and wettability properties were evaluated in the laboratory. The displacement performance of nanoemulsion was evaluated by the spontaneous imbibition experiment. Meanwhile, it compared with the same concentration of SDBS + OP-10 + n-butanol (SOB) system. The results showed that the particle size of the nanoemulsion was 70 ∼ 100 nm. When the concentration of nanoemulsion was 0.10 %, the oil–water IFT could reach 0.091 mN/m. The spontaneous imbibition oil recovery of the nanoemulsion (0.10 wt%) could reach 33.20 %, which was 23.02 % higher than that of SOB system. We also research the spontaneous imbibition displacement mechanism of nanoemulsion and micelle in low-permeability reservoirs. This paper will help to select the best oil displacement agent for the design of enhanced oil recovery (EOR) projects and promote the application of oil displacement agent in oilfield.

Study on the pore structure and capillary water migration characteristics of microbially improved strongly weathered phyllite

Phyllite is in a loose accumulation state after weathering, and there is a lack of suitable slag dump sites. The engineering properties of strongly weathered phyllite with poor strength and water stability can be improved by microbiological modification so that it is suitable for roadbed filling. This paper uses microorganisms to improve the strongly weathered phyllite filler, which does not conform to the hydrophysical properties of highway roadbed filler and studies the effects of different gelling fluids on the improvement. The spontaneous imbibition experiment is carried out on the modified sample to analyze the change rule of pore structure with time. The capillary water migration of the three sample groups is studied by using the nuclear magnetic resonance technique and finite element software. The results show that the carbonates produced by different gelling liquids have different particle encapsulation properties. After the calcium acetate improvement, the crystal content of calcium carbonate reached 20.5%. The pore ratio and equivalent average pore size of the three groups of samples increased with increasing spontaneous imbibition time. The fractal dimension of capillary pores is inversely proportional to the proportion of capillary pores. The capillary water absorption coefficient of the modified sample is 0.01. Both laboratory tests and numerical simulation results show that the improvement effect of calcium acetate is superior to that of the other two gelling liquids. The research results provide a reference for predicting the distribution of groundwater movement in strongly weathered phyllite modified by microorganisms as roadbed fillers.

Nanoparticle-Enhanced Water-Based-Emulsion Fracturing Fluid for Improved Imbibition Recovery in Unconventional Reservoirs: Performance and Mechanism

Summary The conventional friction reducer, typically a water-in-oil (W/O) emulsion, used in slickwater, encounters challenges related to poor environmental friendliness, limited stability, and low activity, hindering its widespread applicability. In this study, we synthesized a water-based emulsion through water dispersion polymerization, incorporating nanoparticles (NPs) into the process to enhance the stability and activity of the polymer emulsion. The result is an environmentally friendly, oil-phase-free, instantly dissolution, and highly efficient friction reducer, intended to optimize the utilization efficiency of slickwater. The NP-enhanced water-based emulsion demonstrated a consistent and spherical dispersion, featuring an average particle size of ~10 μm, maintaining stability for more than 6 months. With rapid dissolution in water, achieved within a mere 38 seconds, it facilitated continuous on-the-fly mixing. Slickwater composed of this emulsion exhibited outstanding application performance, yielding a remarkable 76% reduction in pipeline friction. The presence of NPs and specific monomers facilitated the formation of a spatial network structure that maintains high temperature/shear resistance even after prolonged shear. Moreover, the system exhibited an exceptional capacity for imbibition oil production. Indoor spontaneous imbibition experiments showed a final recovery rate of 32.41% in tight oil cores (~10% higher than conventional systems), and imbibition depth reached 40.2 mm (1.2-fold increase compared with traditional systems). Field experiments were conducted in a tight oil reservoir to validate practical applications; the results further validated the effectiveness of the novel system. The treated wells showcased rapid oil production, reaching an average daily production rate of 55.8 t/d and water content as low as ~31%, satisfying the predicted production target.

Experimental study of adsorption/desorption and enhanced recovery of shale oil and gas by zwitterionic surfactants

Shale reservoirs have the characteristics of low permeability and low porosity. In order to enhance the recovery of shale oil and gas, surfactant flooding is a mature reservoir oil recovery method. However, the adsorption of different surfactants on the reservoir rock surface is restricted, depending on the type of surfactant. Therefore, a zwitterionic surfactant (OPHS) was synthesized from oleic acid, 3-dimethylaminopropylamine and sodium 3-chloro-2hydroxypropanesulfonate, and characterized by FTIR, 1H NMR, and TGA, and the mechanism of the OPHS for enhancing oil and gas recovery on shale surfaces was investigated. The results showed that the critical micelle concentration (CMC) of OPHS surfactant solution is 7.9 × 10-4 mol/L and the γCMC is 27.5 mN/m; the concentration of 0.1 % OPHS surfactant solution could reduce the contact angle of the cores from 127.2° to 38.8°, which resulted in spontaneous imbibition; The absolute Zeta potential of shale particles in the OPHS surfactant solution was measured at 39 mV, whereas in deionized water at 15.3 mV. This difference can be attributed to the formation of a stable hydration film on the surface of shale particles induced by the wetting reversal effect. Spontaneous imbibition experiments showed that a 0.1 % solution of OPHS surfactant was able to increase the recovery rate by more than four times compared to the imbibition solution without added surfactant; In high-pressure gas adsorption/desorption experiments, the OPHS surfactant solution demonstrated a higher affinity for adsorption onto the shale surface. It effectively occupied adsorption sites, ultimately facilitating methane gas desorption from the shale. In summary, OPHS zwitterionic surfactants exhibit the capability to desorb hydrocarbons from shale pores through mechanisms such as wetting reversal and competitive adsorption. This research holds significant potential for advancing the field of shale oil and gas recovery, providing valuable insights for enhancing recovery processes.

Development and performance evaluation of nonionic surfactant-stabilized nanoemulsion for enhanced oil recovery applications in tight reservoir

Nanoemulsions have garnered great attention as a chemical additive for enhanced oil recovery (EOR) technology worldwide due to their small size and unique physicochemical properties. Herein, this work introduces a novel nonionic surfactant-stabilized nanoemulsion prepared using a low-energy method for EOR projects in the Chang 8 tight reservoir. Spontaneous imbibition experiments were conducted in oil-saturated cores, and secondary imbibition experiments were carried out in water-bearing cores. Additionally, core flooding experiments were performed to study the EOR performance of both nanoemulsion and complex surfactant. Finally, the EOR mechanisms were thoroughly investigated, specifically focusing on oil-washing capacity, reduced interfacial tension, and wettability alteration. The designed nanoemulsion, with droplets averaging 10.5 ± 0.7 nm in synthetic formation brine at ambient temperature, exhibits excellent thermal and long-term stability even under reservoir temperature conditions. The oil recovery efficiency of the nanoemulsion system in oil-saturated cores through spontaneous imbibition was 31.28%, representing a 6.42% improvement over the complex surfactant solution. In the secondary imbibition experiments, the nanoemulsion mobilized 8.53% of the residual oil, compared to 4.11% for the complex surfactant. Core flooding experiments revealed that the nanoemulsion system achieved a total oil recovery of 62.69%, outperforming the complex surfactant system by 8.68% during the chemical flooding stage and 1.82% during the subsequent brine flooding stage. The EOR mechanisms of nanoemulsion in tight reservoirs can be attributed to four aspects: reduction of oil/water interfacial tension, wettability alteration, miscibility with crude oil, and increased sweep volume. The generation of the Marangoni effect and the adsorption and diffusion characteristics are essential differences between the nanoemulsion system and the complex surfactant system. The presented findings in this paper could aid in promoting the large-scale use of nanoemulsions in Chang 8 tight reservoirs.

Investigation of the Combination Mechanism of Spontaneous Imbibition and Water Flooding in Tight Oil Reservoirs Based on Nuclear Magnetic Resonance

As conventional oil reservoirs are gradually being depleted, researchers worldwide are progressively shifting their focus towards the development and comprehensive study of tight oil reservoirs. Considering that hydraulic fracturing is one of the main approaches for developing tight sandstone reservoirs, it is of great significance to explore the mechanism of spontaneous imbibition and waterflooding behavior after hydraulic fracturing in tight oil reservoirs. This research delves into the analysis of tight sandstone core samples obtained from the Shahejie Formation in the Bohai Bay Basin. All core samples are used for a series of experiments, including spontaneous imbibition and water flooding experiments. An additional well-shut period experiment is designed to understand the impact and operational dynamics of well shut-in procedures in tight reservoir development. Utilizing nuclear magnetic resonance (NMR) technology, the pore sizes of a sample are divided into three types, namely, macropores (>100 ms), mesopores (10–100 ms), and micropores (<10 ms), to thoroughly assess the fluid distribution and changes in fluid signals during the spontaneous imbibition and water flooding stages. Experimental outcomes reveal that during the spontaneous imbibition stage, oil recovery ranges from 12.23% to 18.70%, predominantly depending on capillary forces. The final oil recovery initially rises and then falls as permeability decreases, while the contribution of micropores progressively grows as the share of mesopores and macropores deceases. With water flooding processes carried out after spontaneous imbibition, enhanced oil recovery is observed between 28.26% and 33.50% and is directly proportional to permeability. The well shut-in procedures can elevate the oil recovery to as high as 47.66% by optimizing energy balance.

Experimental Study on Forced Imbibition and Wettability Alteration of Active Carbonated Water in Low-Permeability Sandstone Reservoir

Summary Imbibition is one of the main mechanisms for fluid transport in porous media. A combination of carbonated water and active water [active-carbonated water (ACW)] has great prospects in enhanced oil recovery (EOR) and carbon reduction processes. To date, the law of hydrocarbon recovery induced by ACW imbibition is not clear. In this paper, the optimal surfactant concentration was first selected through a spontaneous imbibition experiment, and on this basis, CO2 was dissolved to form ACW. The imbibition effects of formation water (FW), surfactant solution DX-1, and ACW under different pressures were compared. The changes in rock wettability in the three imbibition solutions during imbibition were studied by measuring the contact angle. The effect of fracture on ACW imbibition was studied. Finally, the improved NB−1 was calculated to elucidate the mechanism of forced imbibition for EOR. The results show that 0.1% DX-1 produces the optimal imbibition effect. Pressure is positively correlated with imbibition recovery. ACW can significantly improve the imbibition effect due to its wettability reversal ability being better than those of FW and DX-1. CO2 in ACW can be trapped in the formation through diffusion into small rock pores. The contact angles of the three imbibition solutions decrease with increasing pressure. The contact angle between the rock and oil droplet in the ACW is as low as 38.13°. In addition, the fracture increases the contact area between the matrix and the fluid, thereby improving the imbibition effect. The alteration of NB−1 indicates that FW imbibition is gravity-driven cocurrent imbibition. DX-1 and ACW imbibitions are countercurrent imbibitions driven by capillary force and gravity. The above results demonstrate the feasibility of ACW in low-permeability reservoir development and carbon reduction.

Work Flow Screens Surfactants for EOR Through Wettability Alteration

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper URTeC 3866246, “A Systematic Laboratory and Model-Based Surfactant Screening Work Flow for Enhanced Recovery Through Wettability Alteration in the Eagle Ford,” by Jason Jweda, SPE, Russ Bone, SPE, and Hesham El-Sobky, ConocoPhillips, et al. The paper has not been peer reviewed. _ Previous experimental studies and published field trials have shown that injected surfactants can be an effective means of improving recovery. Most experiments, however, have been conducted at ambient rather than reservoir conditions. The complete paper presents a novel approach to screen thermally stable surfactants at high pressures and high temperatures for the explicit purpose of wettability alteration in the operator’s Eagle Ford acreage. Early Internal Efforts Surfactant usage was initiated at the inception of the play. The use of these surfactants was discontinued after approximately 5 years of field development. Fieldwide performance analysis confirmed that off-the-shelf surfactants, on average, did not improve long-term performance statistically. Initial laboratory screening of bespoke surfactant chemistries commenced a few years later. To test surfactant properties near Eagle Ford reservoir conditions, a novel microfluidics experiment was conducted using synthetic microchips designed with reservoir specifications. Twenty-six flowback tests with Eagle Ford crude oil were conducted at 300°F and up to 3,800 psi with six different commercial surfactant chemistries. Imbibition results with the six commercial surfactants were compared with a control case with make-up brine water. Testing performed at 2 gal/thousand increased overall performance for the oil-wet conditions but decreased performance for mixed-wet conditions when compared with 1 gal/thousand. The surfactants tested in this series were temperature-dependent and had clogging tendencies of varying degrees within the microfluidics chips. Methods and Work Flow Promising results from the Amott cell imbibition and other experiments encouraged the authors to evaluate surfactants more holistically, with an emphasis on testing at Eagle Ford reservoir conditions. The first set of experiments involved fluid-stability tests, contact-angle measurements, interfacial-tension (IFT) measurements, static spontaneous-imbibition experiments, and completion-fluid-compatibility tests. An extensive set of commercially available surfactants was screened. The highest potential cationic and nonionic cosurfactant blends that passed through fluid stability, contact-angle, and static spontaneous-imbibition experiments were selected for hydraulic stimulation-fluid compatibility tests. After the compatibility tests, the two best-graded cationic and nonionic cosurfactant blends were used in a novel flowback experiment coupled with multistage nuclear magnetic resonance (NMR) measurements. Mechanistic reservoir simulation models were used to evaluate the production effect of wettability change caused by surfactant injection. The combination of laboratory-based experimentation and reservoir simulations provided strong confidence in holistically evaluating the potential of cosurfactant blends in the Eagle Ford.

Spontaneous imbibition experiments for enhanced oil recovery with silica nanosols

Spontaneous imbibition experiments for enhanced oil recovery with silica nanosols

Synergistic impacts of fracture–matrix system on recovery rate during spontaneous imbibition in tight sandstones

Hydraulic fracturing is considered a promising technology for enhancing the recovery rate from tight oil/gas reservoirs. However, the hydraulic fracturing process inevitably leaves a portion of the fracturing fluid in the reservoir. This causes a noticeable decrease in the recovery rate of oil/gas. Thus, the flow mechanism of fracturing fluids in fracture–matrix system remains unclear. In this study, spontaneous imbibition (SI) experiments were conducted on sandstone samples with different fracture widths. Subsequently, magnetic resonance imaging (MRI) was used to monitor the displacement of the imbibition leading edge at the fracture edges. Finally, the recovery rate was quantified using the T2 spectra of multi-scale pores during the SI process. The experimental results revealed the following: (1) A significant contribution from the pre-rapid growth stage was observed during the SI process. (2) The heterogeneity of sandstone sample resulted in a rough imbibition leading edge and a decreasing gradient in fluid saturation over time. (3) The increase of distilled water in multi-scale pores during the SI process varied, specifically a preferential increase in micropores, followed by mesopores and macropores. (4) When the sandstone sample had a wider fracture, the synergistic effect between the fracture-matrix system was significantly enhanced, and a higher recovery rate was observed.

Nonionic Surfactant Blends for Enhanced Oil Recovery in High-Temperature Eagle Ford Reservoir

Summary Nonionic surfactants have proven successful and cost-effective in enhancing production from conventional and unconventional reservoirs. However, studies into the mechanism and performance of nonionic surfactants have been limited to reservoirs with temperatures below 200°F due to the temperature-dependent physiochemical properties, especially cloudpoint (CP). In this study, nonionic-ionic surfactant blends were designed to create nonionic systems with cloudpoint temperatures (CPTs) above 300°F for wettability alteration in high-temperature reservoirs like the Eagle Ford Shale in Texas, USA. Through CP, wettability, interfacial tension (IFT), and spontaneous imbibition experiments, 22 commercial surfactant samples (individual and blends) were investigated. Results showed that the amount of ionic cosurfactant affected thermal stability, with increasing concentration leading to increasing CPT. Wettability alteration was dependent not only on temperature but also on the class of ionic cosurfactant. Cationic cosurfactants were superior at improving nonionic surfactants’ thermal stability. However, they resulted in oil-wet contact angles (CAs) with increasing temperature. On the other hand, anionic cosurfactants displayed better synergy in terms of wettability alteration, creating strongly water-wet and intermediate-wet CAs at high temperatures. Therefore, the focus was placed on nonionic-anionic surfactant blends for the reservoir samples used in this study. Stable surfactant blends with CPTs from 316°F to 348°F were successfully created for enhanced oil recovery (EOR) applications at high-temperature conditions. Spontaneous imbibition studies using these blends indicated improved recovery by up to 173%. This work validates and builds upon previous studies of surfactant performance, wettability alteration, and IFT while providing new insight into nonionic surfactant blends at temperature conditions not currently available in the literature. It also serves as a template for the surfactant screening and selection process when considering nonionic surfactants.

Influence of extractable organic components on shale wettability: Dongyuemiao member of Jurassic Ziliujing formation in the Fuxing area, Eastern Sichuan Basin

The wettability of reservoir rocks is a critical factor for the petroleum exploration and recovery, which plays an important role on relative permeability, capillary pressure, and ultimate recovery. This study aims to characterize the difference in wettability before and after soxhlet extraction, and reveal the influences of mineral composition, pore structure and extractable organic components on wettability of shales with different lithofacies. Several organic shale samples from the Dongyuemiao (DYM) section of the Jurassic Ziliujing (ZLJ) formation were collected to investigate the mineral composition, pore-size distribution, wettability characteristics and determine the main controlling factors on wettability alteration. Pore type and abundant are observed using argon ion polishing scanning electron microscopy. The pore volume (PV) and pore size distribution (PSD) characteristics before and after extraction were obtained using a combination of nitrogen physisorption and high-pressure mercury intrusion porosimetry (MIP). Spontaneous imbibition (SI) and nuclear magnetic resonance (NMR) experiments were used to investigate the wettability characteristics before and after extraction.Results show that clay, quartz and calcite are dominant minerals in the DYM shales, and three typical lithofacies are identified, including mixed shale (M), argillaceous shale (CM) and calcareous shale (C). Clay mineral interP pore is the dominant pore type in the DYM shales, followed by organic matter (OM) pore. Before the extraction, the DYM shale is more oil lipophilic, while its wettability alters slightly after the extraction. The M shales and C shales maintain lipophilic, while as the CM shales alters from oil wet to mixed wet. Samples with higher quartz have better connectivity of the hydrophilic and lipophilic pore networks, and carbonate minerals play an opposite role. During the extraction process, polar solvents could react with clay minerals to cause pore space expansion, which enhances the water wettability after extraction. Due to the low OM content and poor organic clay complex related pores in the study area, clay minerals have not significant correlation with oil wettability, but influence the water wettability. No correlation occurs between total organic carbon (TOC) content and oil/water wettability of shales before and after extraction. In comparison, macropore has a significant impact on water wettability, while micropore and mesopore play significant impact on oil wettability.

Effects of Fracturing Fluids Imbibition on CBM Recovery: In Terms of Methane Desorption and Diffusion

Summary Hydraulic fracturing technology has been widely used to improve the productivity of the coalbed methane (CBM) reservoir, during which tons of fracturing fluids infiltrate the coal seam. However, the effects of fracturing fluids imbibition on CBM recovery are still unclear. In this study, spontaneous and forced water imbibition experiments in methane-bearing low-volatile bituminous (LVB) coal were conducted at various gas adsorption equilibrium pressures, following which methane desorption and diffusion experiments were performed. These experiments simulated the complete process of fracturing fluid imbibition during well shut-in and subsequent methane production upon reopening, which is helpful in understanding the impact of fracturing fluid imbibition on CBM production. The results show that water imbibition displaces adsorbed methane in the coal matrix, and with reservoir pressure increasing, the displaced effect decreases. Furthermore, the forced imbibition (FI) displaces less methane than the spontaneous imbibition (SI) due to water rapidly filling fractures and blocking methane migration out of the matrix in the FI. In the initial stages of gas production following spontaneous or forced water imbibition, the displaced methane diffuses out of the coal at a rapid rate and then slows down. Furthermore, in the case of FI, a significant amount of residual gas remains after desorption and diffusion due to the water blocking effect. However, the water blocking effect has a minimal impact on coal undergoing SI. In terms of desorption and diffusion, this study provides a comprehensive understanding of the effects of fracturing fluids imbibition on recovery of CBM, which is useful for practical shut-in operations following hydraulic fracturing in LVB coal seams.

Investigation of the effect of diethylene triamine pentaacetic acid chelating agent as an enhanced oil recovery fluid on wettability alteration of sandstone rocks

This study used the diethylene triamine pentaacetic acid (DTPA)-seawater (SW) system to modify the sandstone rock wettability and enhance oil recovery. The investigation involved conducting wettability measurement, Zeta potential measurement, and spontaneous imbibition experiment. The introduction of 5% DTPA-SW solution resulted in a significant decrease in the rock-oil contact angle from 143° to 23°, along with a reduction in the Zeta potential from −2.29 mV to −13.06 mV, thereby altering the rock surface charge and shifting its wettability from an oil-wet state to a strongly water-wet state. The presence or absence of potential determining ions (Ca2+, Mg2+, SO42−) in the solution did not impact the effectiveness of DTPA in changing the rock wettability. However, by tripling the concentration of these ions in the solution, the performance of 5% DTPA-SW solution in changing wettability was impaired. Additionally, spontaneous imbibition tests demonstrated that the 5% DTPA-SW solution led to an increase in oil recovery up to 39.6%. Thus, the optimum mass fraction of DTPA for changing sandstone wettability was determined to be 5%.

Experimental Mechanism for Enhancing Oil Recovery by Spontaneous Imbibition with Surfactants in a Tight Sandstone Oil Reservoir

This study aims to investigate the mechanism behind surfactant enhanced oil recovery under reservoir conditions through experiments on spontaneous imbibition with surfactants. The tight sandstone samples are characterized using cast thin section (CTS), high-pressure mercury intrusion (HPMI), and nuclear magnetic resonance (NMR) to determine their clay mineral composition, pore size distribution, and fluid distribution. Spontaneous imbibition experiments are then conducted using formation water and surfactant solutions as imbibition liquids, with three different types of surfactants─dodecylbenzene sulfonate (DBS), sodium dodecyl sulfate (SDS), and ammonium bromide─at two different concentrations, each to examine the effect of surfactant type. Additionally, the interfacial tension (IFT) between crude oil and different imbibition solutions is measured, and the contact angles of an oil droplet on the core surface in air, formation water, distilled water, and surfactant solution are determined. Finally, the effects of IFT, rock wettability, formation water salinity, and core permeability on final oil recovery by spontaneous imbibition are analyzed. The results indicate that surfactant-assisted spontaneous imbibition primarily operates through IFT reduction, wettability alteration, and emulsification of crude oil. However, ultralow IFT may lead to low ultimate oil recovery. To increase the ultimate oil recovery of spontaneous imbibition, reducing the salinity of the surfactant solution and creating microfractures can be effective strategies.