Low-permeability Cores Research Articles

High-Frequency Electromagnetic Behavior, Impedance Modeling, and Enhancement of Low-Permeability Powder Cores

High-Frequency Electromagnetic Behavior, Impedance Modeling, and Enhancement of Low-Permeability Powder Cores

Synergistic anionic/zwitterionic mixed surfactant system with high emulsification efficiency for enhanced oil recovery in low permeability reservoirs

Emulsification is one of the important mechanisms of surfactant flooding. To improve oil recovery for low permeability reservoirs, a highly efficient emulsification oil flooding system consisting of anionic surfactant sodium alkyl glucosyl hydroxypropyl sulfonate (APGSHS) and zwitterionic surfactant octadecyl betaine (BS-18) is proposed. The performance of APGSHS/BS-18 mixed surfactant system was evaluated in terms of interfacial tension, emulsification capability, emulsion size and distribution, wettability alteration, temperature-resistance and salt-resistance. The emulsification speed was used to evaluate the emulsification ability of surfactant systems, and the results show that mixed surfactant systems can completely emulsify the crude oil into emulsions droplets even under low energy conditions. Meanwhile, the system exhibits good temperature and salt resistance. Finally, the best oil recovery of 25.45% is achieved for low permeability core by the mixed surfactant system with a total concentration of 0.3 wt% while the molar ratio of APGSHS:BS-18 is 4:6. The current study indicates that the anionic/zwitterionic mixed surfactant system can improve the oil flooding efficiency and is potential candidate for application in low permeability reservoirs.

Development and Characterization of Thermoresponsive Smart Self-Adaptive Chitosan-Based Polymer for Wellbore Plugging.

To meet the escalating demand for oil and gas exploration in microporous reservoirs, it has become increasingly crucial to develop high-performance plugging materials. Through free radical grafting polymerization technology, a carboxymethyl chitosan grafted poly (oligoethylene glycol) methyl ether methyl methacrylate acrylic acid copolymer (CCMMA) was successfully synthesized. The resulting CCMMA exhibited thermoresponsive self-assembling behavior. When the temperature was above its lower critical solution temperature (LCST), the nanomicelles began to aggregate, forming mesoporous aggregated structures. Additionally, the electrostatic repulsion of AA chains increased the value of LCST. By precisely adjusting the content of AA, the LCST of CCMMA could be raised from 84.7 to 122.9 °C. The rheology and filtration experiments revealed that when the temperature surpassed the switching point, CCMMA exhibited a noteworthy plugging effect on low-permeability cores. Furthermore, it could be partially released as the temperature decreased, exhibiting temperature-switchable and self-adaptive plugging properties. Meanwhile, CCMMA aggregates retained their reversibility, along with thermal thickening behavior in the pores. However, more detailed experiments and analysis are needed to validate these claims, such as a comprehensive study of the CCMMA copolymer's physical properties, its interaction with the reservoir environment, and its performance under various conditions. Additionally, further studies are required to optimize its synthesis process and improve its efficiency as a plugging material for oil and gas recovery in microporous reservoirs.

Experimental Study on SiO2 Nanoparticles-Assisted Alpha-Olefin Sulfonate Sodium (AOS) and Hydrolyzed Polyacrylamide (HPAM) Synergistically Enhanced Oil Recovery

The purpose of this study is to investigate the use of SiO2 nanoparticles in assisting with surfactants and polymers for tertiary oil recovery, with the aim of enhancing oil recovery. The article characterizes the performance of SiO2 nanoparticles, including particle size, dispersion stability, and zeta potential, evaluates the synergistic effects of nanoparticles with alpha-olefin sulfonate sodium (AOS) surfactants and hydrolyzed polyacrylamide (HPAM) on reducing interfacial tension and altering wettability, and conducts core flooding experiments in rock cores with varying permeabilities. The findings demonstrate that the particle size decreased from 191 nm to 125 nm upon the addition of SiO2 nanoparticles to AOS surfactant, but increased to 389 nm upon the addition of SiO2 nanoparticles to HPAM. The dispersibility experiment showed that the SiO2 nanoparticle solution did not precipitate over 10 days. After adding 0.05% SiO2 nanoparticles to AOS surfactant, the zeta potential was −40.2 mV, while adding 0.05% SiO2 nanoparticles to 0.1% HPAM resulted in a decrease in the zeta potential to −25.03. The addition of SiO2 nanoparticles to AOS surfactant further reduced the IFT value to 0.19 mN/m, altering the rock wettability from oil-wet to strongly water-wet, with the contact angle decreasing from 110° to 18°. In low-permeability rock core oil displacement experiments, the use of AOS surfactants and HPAM for enhanced oil recovery increased the recovery rate by 24.5% over water flooding. The recovery rate increased by 21.6% over water flooding in low-permeability rock core experiments after SiO2 nanoparticles were added and surfactants and polymers were utilized for oil displacement. This is because the nanoparticles blocked small pore throats, resulting in increased resistance and hindered free fluid flow. The main causes of this plugging are mutual interference and mechanical entrapment, which cause the pressure differential to rise quickly. In high-permeability rock core oil displacement experiments, the use of AOS surfactants and HPAM for oil recovery increased the recovery rate by 34.6% over water flooding. Additionally, the recovery rate increased by 39.4% over water flooding with the addition of SiO2 nanoparticles and the use of AOS surfactants and HPAM for oil displacement. Because SiO2 nanoparticles create wedge-shaped structures inside highly permeable rock cores, they create structural separation pressure, which drives crude oil forward and aids in diffusion. This results in a comparatively small increase in pressure differential. Simultaneously, the nanoparticles change the rock surfaces’ wettability, which lowers the amount of crude oil that adsorbs and improves oil recovery.

Multi-supramolecular and double-network strategy improves rheological properties and oil displacement efficiency of polymers

In enhanced oil recovery (EOR), the application of polymer systems in harsh reservoir conditions is limited. This study conducted a proof-of-concept study of multi-supramolecular interactions and dual-network strategies, motivated by the desire to gain insights into the effectiveness of these higher-order self-assembled polymer flooding. Xanthan gum dual network supramolecular polymer (DN-HXG) system was obtained by multi-supramolecular cross-linking of polyacrylamide and xanthan gum, and compared with hydrophobic polyacrylamide/hydrophobic xanthan gum (HMPAM/MXG) mixture and polyacrylamide/xthan gum (HPAM/XG) mixture. The thickening and temperature and salt tolerance mechanisms of DN-HXG were analyzed by environmental scanning electron microscopy (ESEM), dynamic light scattering (DLS) and fluorescence spectra. The results show that the DN-HXG system has excellent viscoelastic and shear resistance. Due to the presence of multiple supramolecular interactions and rigid xanthan gum molecular chains, DN-HXG can withstand environments of more than 120 ℃ and 50 g/L salinity, which has good applicability in harsh reservoirs. In laboratory oil displacement experiments, DN-HXG shows obvious advantages in low-permeability core, and the recovery rate of DN-HXG is more than 20 % higher than that of conventional polymer. These experiments show that the strategies described can be applied to other synthetic polymers and biopolymers to improve their oil displacement properties.

Multifractal estimation of NMR T2 cut-off value in low-permeability rocks considering spectrum kurtosis: SMOTE-based oversampling integrated with machine learning

The transverse relaxation time (T2) cut-off value plays a crucial role in nuclear magnetic resonance for identifying movable and immovable boundaries, evaluating permeability, and determining fluid saturation in petrophysical characterization of petroleum reservoirs. This study focuses on the systematic analysis of T2 spectra and T2 cut-off values in low-permeability reservoir rocks. Analysis of 36 low-permeability cores revealed a wide distribution of T2 cut-off values, ranging from 7 to 50 ms. Additionally, the T2 spectra exhibited multimodal characteristics, predominantly displaying unimodal and bimodal morphologies, with a few trimodal morphologies, which are inherently influenced by different pore types. Fractal characteristics of pore structure in fully water-saturated cores were captured through the T2 spectra, which were calculated using generalized fractal and multifractal theories. To augment the limited dataset of 36 cores, the synthetic minority oversampling technique was employed. Models for evaluating the T2 cut-off value were separately developed based on the classified T2 spectra, considering the number of peaks, and utilizing generalized fractal dimensions at the weight <0 and the singular intensity range. The underlying mechanism is that the singular intensity and generalized fractal dimensions at the weight <0 can detect the T2 spectral shift. However, the T2 spectral shift has negligible effects on multifractal spectrum function difference and generalized fractal dimensions at the weight >0. The primary objective of this work is to gain insights into the relationship between the kurtosis of the T2 spectrum and pore types, as well as to predict the T2 cut-off value of low-permeability rocks using machine learning and data augmentation techniques.

Product migration and regional reaction characteristics in the autothermic pyrolysis in-situ conversion process of low-permeability Huadian oil shale core

Product migration and regional reaction characteristics of low-permeability oil shale cores in the autothermic pyrolysis in-situ conversion have not been investigated. In this study, an in-situ autothermic pyrolysis simulation experiment was conducted using a pressed cylindrical Huadian oil shale core, and systematic geochemical analyses were performed at different regions of the core after the experiments. The results showed that a clear thin grey-white main channel was formed inside the low-permeability core from the gas injection end to the outlet end because of the uneven advancement of the autothermic reaction after the experiment. Moreover, the free hydrocarbon products mainly transported along the main channel towards the outlet end and formed a significant accumulation at the end of the core. In addition, according to the results of pyrolysis hydrocarbon and total organic carbon determination, the core was divided into four typical reaction zones: autothermic, cracking, preheating, and virgin, which were distributed sequentially outwards along both sides of the main channel. Finally, based on the above results and analysis, two construction strategies were suggested for the autothermic pyrolysis in-situ conversion process.

Study on Production Characteristics during N2 Flooding in Low Permeability Reservoirs: Effect of Matrix Permeability and Fracture

The N2 flooding enhanced oil recovery process is an important technical means for the development of low permeability reservoirs due to its good energy enhancement effect and good injectivity. Low permeability reservoirs have a large permeability span and strong heterogeneity, which will have a significant impact on gas injection development. In order to explore the influence of matrix permeability and fractures on the production characteristics of N2 flooding, this study conducted a series of displacement experiments with full-scale matrix permeability (0.1–50 mD) and different fracture conditions. The research results indicate that, in non-fracture low permeability cores, the pressure difference decreased with the matrix permeability increase, and the volume of N2 injection required to achieve the highest injection pressure decreased. In addition, the increase in matrix permeability accelerates the gas breakthrough and gas channeling, but is beneficial for improving no-gas oil recovery and ultimate oil recovery due to the decrease in crude oil flow resistance. The impact of different matrix permeability ranges on production characteristics varies. When the matrix permeability is less than 2 mD, the characteristics of oil and gas production are significantly affected by changes in matrix permeability. When the matrix permeability is greater than 2 mD, the impact of changes in matrix permeability on development effectiveness is weakened. The existence of fracture causes a high permeability channel to appear in the low permeability matrix, exacerbating the gas breakthrough and channeling, and significantly reducing the utilization of matrix crude oil (about a 50% decrease in oil recovery). The increase in matrix permeability is beneficial for weakening the heterogeneity between fractures and the matrix, alleviating the gas channeling, thereby increasing the swept volume in the low permeability matrix and improving oil recovery.

CO2 Injection for Enhanced Gas Recovery and Geo-Storage in Complex Tight Sandstone Gas Reservoirs

With the popularization of natural gas and the requirements for environmental protection, the development and utilization of natural gas is particularly important. The status of natural gas in China’s oil and gas exploration and development is constantly improving, and the country is paying more and more attention to the exploitation and utilization of natural gas. The Upper Paleozoic tight sandstone in the Ordos Basin is characterized by low porosity, low permeability and a large area of concealed gas reservoirs. By injecting carbon dioxide into the formation, the recovery rate of natural gas can be improved, and carbon neutrality can be realized by carbon sequestration. Injecting greenhouse gases into gas reservoirs for storage and improving recovery has also become a hot research issue. In order to improve the recovery efficiency of tight sandstone gas reservoirs, this paper takes the complex tight sandstone of the Upper Paleozoic in the Ordos Basin as the research object; through indoor physical simulation experiments, carried out the influence of displacement rate, fracture dip angle, core permeability, core dryness and wetness on CO2 gas displacement efficiency and storage efficiency; and analyzed the influence of different factors on gas displacement efficiency and storage efficiency to improve the recovery and storage efficiency. The research results show that under different conditions, when the injection pore volume is less than 1 PV, the relationship between the CH4 recovery rate and the CO2 injection pore volume is linear, and the tilt angle is 45°. When the injection pore volume exceeds 1 PV, the CH4 recovery rate increases slightly with the increase in displacement speed, the recovery rate of CO2 displacement CH4 is between 87–97% and the CO2 breakthrough time is 0.7 PV–0.9 PV. In low-permeability and low-speed displacement cores, the diffusion of carbon dioxide molecules is more significant. The lower the displacement speed is, the earlier the breakthrough time is, and the final recovery of CH4 slightly decreases. Gravity has a great impact on carbon sequestration and enhanced recovery. The breakthrough of high injection and low recovery is earlier, and the recovery of CH4 is about 3.3% lower than that of low injection and high recovery. The bound water causes the displacement phase CO2 to be partially dissolved in the formation water, and the breakthrough lags about 0.1 PV. Ultimately, the CH4 recovery factor and CO2 storage rate are higher than those of dry-core displacement. The research results provide theoretical data support for CO2 injection to improve recovery and storage efficiency in complex tight sandstone gas reservoirs.

Study on the imbibition recovery trends in low-permeability cores under high-pressure CO2

Imbibition plays a crucial role in extracting crude oil from low-permeability reservoir matrices. After CO2 is injected into the low-permeability reservoirs for development, both CO2 and surfactants often coexist in the imbibition fluid. While previous studies have mainly focused on the individual presence of CO2 or surfactants, limited research has been conducted on their coexistence. In this paper, the imbibition recovery trends in low-permeability cores under high-pressure CO2 are investigated by measuring the imbibition efficiency, the three-phase contact angle (CA), and the oil-water interfacial tension (IFT). The findings of this research indicate that the surfactant significantly enhances the interface characteristics, substantially increases the imbibition rate, and improves recovery by more than 14 %. Temperature has a greater impact on the interface characteristics compared to pressure, directly influencing the distribution of SDS molecules at the interface. Despite temperature elevation leading to increased IFT and reduced concentration of charged ions, it still enhances the rock hydrophilicity and improves imbibition efficiency. Pressure affects the interface characteristics mainly by modifying CO2 solubility. With increasing pressure, the IFT decreases, the concentration of charged ions increases, and the electrostatic repulsion between ions is enhanced, ultimately enhancing rock hydrophilicity and significantly boosting imbibition efficiency. The coexistence of CO2 and SDS further improves the interface characteristics, exhibiting synergistic effects in reducing IFT and enhancing rock hydrophilicity. These research findings contribute to a deeper understanding of the imbibition mechanism and provide theoretical support for the development and application of CO2 injection in the field.

Characteristics and mechanism of smart fluid for sweep-controlling during CO2 flooding

A smart response fluid was designed and developed to overcome the challenges of gas channeling during CO2 flooding in low-permeability, tight oil reservoirs. The fluid is based on Gemini surfactant with self-assembly capabilities, and the tertiary amine group serves as the response component. The responsive characteristics and corresponding mechanism of the smart fluid during the interaction with CO2/oil were studied, followed by the shear characteristics of the thickened aggregates obtained by the smart fluid responding to CO2. The temperature and salt resistance of the smart fluid and the aggregates were evaluated, and their feasibility and effectiveness in sweep-controlling during the CO2 flooding were confirmed. This research reveals: (1) Thickened aggregates could be assembled since the smart fluid interacted with CO2. When the mass fraction of the smart fluid ranged from 0.05% to 2.50%, the thickening ratio changed from 9 to 246, with viscosity reaching 13 to 3100 mPa·s. As a result, the sweep efficiency in low-permeability core models could be increased in our experiments. (2) When the smart fluid (0.5% to 1.0%) was exposed to simulated oil, the oil/fluid interfacial tension decreased to the level of 1×10−2 mN/m. Furthermore, the vesicle-like micelles in the smart fluid completely transformed into spherical micelles when the fluid was exposed to simulated oil with the saturation greater than 10%. As a result, the smart fluid could maintain low oil/fluid interfacial tension, and would not be thickened after oil exposure. (3) When the smart fluid interacted with CO2, the aggregates showed self-healing properties in terms of shear-thinning, static-thickening, and structural integrity after several shear-static cycles. Therefore, this fluid is safe to be placed in deep reservoirs. (4) The long-term temperature and salt resistance of the smart fluid and thickened aggregates have been confirmed.

Effect of surfactant on oil displacement efficiency of imbibition/huff and puff in low permeability reservoirs

ABSTRACT Low permeability and tight reservoirs are rich in microscale and even nanoscale pores, resulting in a large interfacial tension between oil and water in the pores. Surfactant can effectively improve the oil displacement efficiency during imbibition and huff and puff. In this paper, the low permeability cores with different permeability are taken as the research object, and the effects of surfactant and distilled water on the oil displacement efficiency of imbibition/huff and puff are compared and analyzed using the nuclear magnetic resonance technology. Results show that: (a) Huff and puff can significantly improve displacement efficiency, and there are mainly three reasons: the soaking time, surfactants improve infiltration efficiency, and elastic energy. (b) Imbibition is a spontaneous phenomenon in tight reservoirs, while huff and puff is artificially manipulated. (c) Due to the slow infiltration process, as the soaking time increases, the oil displacement efficiency increases. (d) when the pressure is increased from 0.1 MPa to 12 MPa, the oil recovery and displacement efficiency are increased by about 2 times. (e) Compared with imbibition displacement, huff and puff can significantly improve displacement efficiency. (f) The T2 spectrum shows that the oil displacement efficiency of surfactant imbibition is higher, and the oil displacement efficiency of imbibition is significantly lower than that of huff and puff.

Key parameters and dominant EOR mechanism of CO2 miscible flooding applied in low-permeability oil reservoirs

CO2 miscible flooding is a prospective production method to enhance oil recovery (EOR), especially in low-permeability reservoirs. However, there is a lack of comprehensive and systematic understanding of the key parameters and dominant EOR mechanism of CO2 miscible flooding. In this work, the sensitivity of key parameters, such as oil viscosity, permeability, permeability ratio, and pressure, is analyzed by CO2 flooding physical simulation experiments. The adjuvants for CO2 miscible flooding of the Changqing crude oils are evaluated and optimized. The production performance of overpressure CO2 miscible flooding is studied by CO2 core flood test, and the oil micro-distribution before and after CO2 miscible flooding is characterized using nuclear magnetic resonance (NMR), and the micro EOR mechanism of CO2 miscible flooding is revealed. The results show that CO2 immiscible flooding is suitable for the development of low-viscosity crude oil (<50 mPa s), especially for oil viscosity of less than 10 mPa s. CO2 miscible flooding is advisable for low-permeability and medium and high-permeability reservoirs, especially for reservoir permeability of higher than 10 mD. Above the MMP, the oil recovery factor is over 85% and the increase rate slows down with pressure, CO2 miscible flooding is preferred for the high-pressure reservoir. CO2 miscible flooding is applicable for reservoirs with a permeability ratio of less than 2.5, especially for a permeability ratio of less than 2. Compared with 0.8 times MMP pure CO2 flooding, the time of gas channeling, and oil recovery for CO2 miscible flooding is delayed from 0.69 PV to 0.76 PV, and enhanced to 93.04% from 72.61%, respectively, with the help of adjuvants for CO2 miscible flooding, NP-9. The adjuvants for CO2 miscible flooding could effectively promote the realization of miscible flooding for CO2 and crude oils with an injection pressure of less than the MMP. CO2 has excellent oil displacement ability in low-permeability reservoirs, especially for miscible flooding, and the core oil saturation is obviously reduced. Overpressure CO2 miscible flooding could expand the swept volume and more efficiently displace oil in low-permeability reservoirs compared to an injection pressure of 1.0 times MMP. After overpressure CO2 miscible flooding, the residual oil in the low-permeability cores is distributed more evenly.

Inserted-Shunt Integrated Planar Transformer With Low Secondary Leakage Inductance for LLC Resonant Converters

The leakage inductance of an integrated transformer is usually utilized as the series inductor of an <italic xmlns:mml="http://www.w3.org/1998/Math/MathML" xmlns:xlink="http://www.w3.org/1999/xlink">LLC</i> topology. However, leakage inductance exists on both primary and secondary sides of an integrated transformer and secondary leakage inductance leads the control and design of the converter to difficulty. In this article, a novel topology forinserted-shunt integrated transformers is proposed that has low secondary leakage inductance. The inserted shunt of the proposed topology is not segmental and can be located conveniently within the transformer. In addition, the inserted shunt does not require low permeability core material, simplifying its manufacture. The design and modeling of the proposed transformer topology are presented and verified by finite-element analysis and experimental implementation. The proposed topology is also compared with a recently published inserted-segmental-shunt integrated transformer. It is shown that the proposed transformer provides higher efficiency and lower ac resistance. Finally, an <italic xmlns:mml="http://www.w3.org/1998/Math/MathML" xmlns:xlink="http://www.w3.org/1999/xlink">LLC</i> resonant converter is implemented to examine the performance of the proposed integrated transformer in practice.

Performance evaluation of oil-displacement viscoelastic zwitterionic surfactant fracturing fluid

Viscoelastic surfactant (VES) fracturing fluid has advantages in sand-carrying and micelle-breaking without residues, while its practical applications are always limited due to the poor temperature and shearing resistance. Accordingly, a kind of stearicamide propyl hydroxylsulfobetaine (SPHB) was self-synthesized by using stearic acid, N, N-dimethyl-1,3-propane diamine, and sodium 3-shloro-2-hydroxypropane sulfonate as raw materials, and a novel VES fracturing fluid (HCF) was prepared by optimizing the ratio of SPHB and counterion. The composition of the novel fracturing fluid system was determined according to the viscosity varies with temperature. Moreover, the temperature and shearing resistance, viscoelastic, sand-carrying, drag reduction, micelle-breaking, and oil displacement properties of the system were systematically studied. The results showed that the optimum molar ratio of SPHB to salicylate counterion in the fracturing fluid system was 1:1. Surface tension test showed the critical micelle concentration (CMC) of SPHB surfactant solution is 6.27 × 10-4 mol /L and the surface tension γcmc is 40 mN/m. The apparent viscosity of the novel fluid was kept above 50 mPa·s after continuous sheared for 60 min under the condition of 170 s−1 at 130 ℃. Besides, it has good viscoelastic property and sand-carrying performance, and the experimental results showed that the drag reduction rate of the novel fluid reaches more than 60% at different temperatures. The micelle-breaking performance of the novel system was perfect. There is basically no solid residue in the micelle-breaking solution, and the permeability damage rate of the micelle-breaking liquid to the natural core was only 9.41%, which showed the novel fluid has the characteristics of low damage. Finally, low-permeability natural cores were used to carry out micelle-breaking fluid oil displacement experiments, including single core flooding and double-tube parallel core flooding, and the mechanism of micelle-breaking fluid improving oil recovery was revealed.

Study of the Influence of Dynamic and Static Capillary Forces on Production in Low-Permeability Reservoirs

Low-permeability reservoirs have strong heterogeneity, and the production prediction based on traditional seepage model is not accurate enough. The dynamic capillary-force seepage model can characterize the dynamic heterogeneity of seepage and more accurately describe the oil–water flow process. In this paper, the calculation formula of the dynamic capillary force is obtained through a real low-permeability core experiment, and the seepage model of dynamic capillary force is established. Based on the model, the authors quantitatively study the effects of formation pressure, heterogeneity and production speed on dynamic capillary force through numerical solutions. It is found that compared with the traditional static capillary-force seepage model, the dynamic capillary-force seepage model makes the predicted water cut increase and the recovery factor decrease. With the increase in development time, formation pressure and production rate will make the effect of dynamic capillary force more obvious. According to the comparison of heterogeneous reservoir models, results show that the horizontal heterogeneity will strengthen the dynamic capillary-force effect, while the vertical heterogeneity will weaken the dynamic capillary-force effect. In the range of research parameters, the recovery ratio predicted by the dynamic capillary-force seepage model can be reduced by 4.7%. A new oil–water seepage model is proposed, which can characterize the spatial difference and dynamic change of low-permeability reservoirs with time. It is of great significance for describing the remaining oil distribution of low-permeability reservoirs in detail and making decisions on efficient EOR measures.

Enhanced oil recovery in fractured low-permeability reservoirs by a novel gel system prepared by sustained-release crosslinker and water-soluble thixotropic polymer

Polymer gels have been widely used in improving oil recovery and decreasing excessive water production in heterogeneous reservoirs after the long-term water flooding process. However, the high initial viscosity of polymer and the short gelation time still restricts the performance of polymer-based in situ cross-linked gels for in-depth conformance control. Herein, a novel gel system formed by in-situ crosslinking of water-soluble thixotropic polymer (WTP) and sustained-release crosslinker (SRC) was proposed. The WTP was synthesized by acrylamide, 2-acrylamido-2-methylpropanesulfonic acid, and N-[3-(dimethylamino)propyl] methacrylamide. It exhibits low viscosity under high shear rates and becomes thick under low shear rates, which ensures good injectability during the injection process and high gelation strength after cross-linking. The SRC was prepared by coating poly(ethyleneimine) (PEI) into the W/O/W multiple emulsions. The sustained-release mechanisms were well elaborated by confocal laser scanning microscopy (CLSM) observations. Only after the demulsification of multiple emulsions, the PEI would be released from the internal aqueous phase to the external aqueous phase. Therefore, these emulsions can be employed to deliver crosslinkers to specified targets in deep regions and prolong the release of crosslinkers to prevent undesirable crosslinking reactions near the injecting wells. According to the environmental scanning electron microscope (ESEM) observations and viscosity measurements, the low viscosity and an incompact spatial network could be observed in SRC/WTP gel system in the first 17 d, after which the PEI molecules were released to the external aqueous phase and cross-linked with WTP, forming the solid gel with small pores and yielding a high viscosity of 8793 mPa⋅s. Rheology tests have demonstrated that the elastic modules and the liner viscoelastic region of the novel gel system was nearly two times and twenty times than the traditional polymer gel, indicating higher gelation strength and better shear resistance. The core flooding tests showed that the SRC/WTP gel system had good injectability and could effectively plug the millimeter and submillimeter-sized cracks in low-permeability cores. 0.6 pore volume (PV) of SRC/WTP gel system with 3 gel slugs and a low injection rate can yield the best plugging performance in fractured core samples. And the gelation time shortens with the decrease of fracture apertures. Most importantly, the field tests in Ordos Basin verified the desirable EOR performance of the SRC/WTP gel system in fractured low-permeability reservoirs.

Experimental study on the in-situ foam performance stabilized by microbial polysaccharide and its diverting characteristics at high temperature

Foam fluid shows good performance as diverting agent for reservoir stimulation, but complex generation procedure and high flow friction restrict its further application especially in offshore fields. To overcome these limitations, the objective of this study is to create stable in-situ foam system and investigate its potential in diverting fluid in heterogeneous reservoirs at high temperature. To prepare in-situ foam system, self-generated gas system was analyzed in terms of gas production volume and production efficiency. Foaming agents and foam stabilizers were optimized at the temperatures ranging from 70 ℃ to 90 ℃. Then in-situ foaming performance of the system combining self-generated gas reactants (sodium nitrite and ammonium chloride), the foaming agent (alpha olefin sulfonate), and the foam stabilizer (diutan gum) without blender was investigated based on foaming volume and bulk stability. Single core and parallel core flooding experiments were applied to investigate the plugging ability and diverting characteristics of in-situ foam. The results showed that the large pore volume was blocked by in-situ foam even at 150 ℃ as shown by the increase of residual resistance factor during subsequent water flooding. Parallel core flooding experiments also proved the diverting ability of in-situ foams as the diversion ratio of low-permeability core was higher than that of high-permeability core during subsequent water flooding. Moreover, the diversion performance of in-situ foam strongly depended on the permeability contrast, environment temperature, permeability of low-permeability core, and injection rate. Although diversion failed when permeability contrast was more than 10, in-situ foam also had good thermal stability and diverting ability at 150 ℃ in the permeability contrast range of 3 to 8. Such stable in-situ foam shows promising potential as diverting agent in heterogeneous formation for reservoir stimulation at high temperature.

A COMPARATIVE STUDY ON THE OIL RECOVERY PERFORMANCE OF THE CO2 AND N2 HUFF-N-PUFF PROCESSES IN LOW PERMEABILITY CORES

The gas huff-n-puff process has been widely employed in low permeability reservoir development practices. At present, the understanding of synergistic effects of different injection fluids and rock permeability is still limited and is worthy of in-depth investigation. Therefore, laboratory studies on oil recovery performance of supercritical CO&lt;sub&gt;2&lt;/sub&gt; (scCO&lt;sub&gt;2&lt;/sub&gt;) and N&lt;sub&gt;2&lt;/sub&gt; huff-n-puff processes in ultra-low (&amp;#60; 0.5 mD), extra-low (0.5-1 mD), and average-low permeability (1-10 mD) core samples were systematically investigated. More effective cycles could be achieved in the CO&lt;sub&gt;2&lt;/sub&gt; huff-n-puff process than in the N&lt;sub&gt;2&lt;/sub&gt; process. The CO&lt;sub&gt;2&lt;/sub&gt; huff-n-puff operation could produce 29.9&amp;#37; oil in the ultralow permeability core, which is obviously higher than 20.2&amp;#37; for N&lt;sub&gt;2&lt;/sub&gt;. With increasing core permeability, the oil recovery ratio for both the scCO&lt;sub&gt;2&lt;/sub&gt; and N&lt;sub&gt;2&lt;/sub&gt; huff-n-puff processes increases as well. Laboratory results show oil recovery ratios of 33.1&amp;#37; and 47.3&amp;#37; for the scCO&lt;sub&gt;2&lt;/sub&gt; process in 0.5 mD and 10 mD cores and 36.3&amp;#37; and 49.1&amp;#37; for the N&lt;sub&gt;2&lt;/sub&gt; process in 0.5 mD and 9.5 mD cores, respectively. Although the oil recovery rates for the N&lt;sub&gt;2&lt;/sub&gt; and CO&lt;sub&gt;2&lt;/sub&gt; huff-n-puff processes are close in the 0.5 mD and 10 mD cores, the effective oil extraction pressure for the scCO&lt;sub&gt;2&lt;/sub&gt; puff process is found to be 5&amp;#126;10 MPa, which is much higher than 0&amp;#126;2 MPa for the N&lt;sub&gt;2&lt;/sub&gt; puff process. The study's findings can help provide a better understanding of the oil extraction behaviors in the huff-n-puff process with different injection fluids as well as in different low permeability cores.

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.