Low-permeability Sandstone Reservoirs Research Articles

Evolution of CO2 Storage Mechanisms in Low-Permeability Tight Sandstone Reservoirs

Understanding the storage mechanisms in CO2 flooding is crucial, as many carbon capture, utilization, and storage (CCUS) projects are related to enhanced oil recovery (EOR). CO2 storage in reservoirs across large timescales undergoes the two storage stages of oil displacement and well shut-in, which cover multiple replacement processes of injection–production synchronization, injection only with no production, and injection–production stoppage. Because the controlling mechanism of CO2 storage in different stages is unknown, the evolution of CO2 storage mechanisms over large timescales is not understood. A mathematical model for the evaluation of CO2 storage, including stratigraphic, residual, solubility, and mineral trapping in low-permeability tight sandstone reservoirs, was established using experimental and theoretical analyses. Based on a detailed geological model of the Huaziping oilfield, calibrated with reservoir permeability and fracture characteristic parameters obtained from well test results, a dynamic simulation of CO2 storage for the entire reservoir life cycle under two scenarios of continuous injection and water–gas alternation were considered. The results show that CO2 storage exhibits the significant stage characteristics of complete storage, dynamic storage, and stable storage. The CO2 storage capacity and storage rate under the continuous gas injection scenario (scenario 1) were 6.34 × 104 t and 61%, while those under the water–gas alternation scenario (scenario 2) were 4.62 × 104 t and 46%. The proportions of storage capacity under scenarios 1 and 2 for structural or stratigraphic, residual, solubility, and mineral trapping were 33.36%, 33.96%, 32.43%, and 0.25%; and 15.09%, 38.65%, 45.77%, and 0.49%, respectively. The evolution of the CO2 storage mechanism showed an overall trend: stratigraphic and residual trapping first increased and then decreased, whereas solubility trapping gradually decreased, and mineral trapping continuously increased. Based on these results, an evolution diagram of the CO2 storage mechanism of low-permeability tight sandstone reservoirs across large timescales was established.

Study on Sensitivity Mechanism of Low-Permeability Sandstone Reservoir in Huilu Area of Pearl River Mouth Basin

Reservoir sensitivity is a parameter that is used to evaluate the degree of change in reservoir permeability under the influence of external fluids. Accurate evaluation of reservoir sensitivity is conducive to the optimization of fluid parameters during exploration and development. Taking the Wenchang Formation and Enping Formation of the Paleogene in the Huilu area of the Pearl River Mouth Basin as the research object, reservoir sensitivity experiments were carried out. Combined with the corresponding experimental results obtained using methods such as thin section identification, scanning electron microscopy (SEM), X-ray diffraction (XRD), mercury intrusion porosimetry (MIP), and screening analysis, based on mineral sensitization and pore structure sensitization, qualitative and quantitative evaluations of reservoir sensitivity were carried out, and factors affecting sensitivity and sensitization mechanisms were analyzed. This work shows the following: (1) The sandstone reservoirs in the two areas have the same clay type, but the total clay content of the Wenchang Formation is greater than that of the Enping Formation. The porosity of the Wenchang Formation is less developed than the Enping Formation. (2) The Wenchang Formation has weak or moderately weak water sensitivity and moderately weak or moderately strong flow velocity sensitivity. The water sensitivity of the Enping Group samples is moderately weak or moderately strong, the flow rate sensitivity is moderately weak, the alkali sensitivity is weak, the acid sensitivity is moderately weak, and the salinity sensitivity is moderately weak or moderately strong. (3) The sensitivity of the Wenchang Formation is mainly affected by the content of clay minerals. The sensitivity of the Enping Formation is also affected by the clay content and type. Although the clay content is not high, the permeability is more susceptible to sensitivity due to the pore structure and debris particle distribution characteristics. These conclusions are beneficial for the selection of fluid parameters and efficient reservoir development.

The joint controls of tectonism, sedimentation and diagenesis on reservoir quality in the East China Sea Basin

Variation in reservoir quality is especially important in low-permeability and tight sandstone reservoirs. By using log, seismic and core test data, we developed a method that uses tectonism, sedimentation and diagenesis to evaluate sweet spot distribution of the third (Mbr 3), fourth (Mbr 4) and fifth (Mbr 5) members of the Oligocene Huagang Formation in the Xihu Depression, East China Sea Basin. Sweet spot maps of the Mbr 3, Mbr 4 and Mbr 5 sandstone reservoirs were compiled by superposing tectonic locations, depositional microfacies and diagenetic facies. Sweet spots were classified into three types. Mbr 3 exhibits type I and type II sweet spots, Mbr 4 exhibits type I, type II and type III sweet spots, and Mbr 5 exhibits type II and type III sweet spots. In the Oligocene, tectonism and climatic controlled the depositional microfacies, sandstone grain size and clastic composition of the Mbr 5, Mbr 4 and Mbr 3 members, which were deposited in a braided river delta setting that ranged from delta-front distal part to proximal part. From late Oligocene to present, along with depositional microfacies, diagenetic stage, diagenetic facies and reservoir properties, the joint control of tectonism, sedimentation and diagenesis determined the distribution of diagenetic facies, and was used to develop a synthetic pattern for reservoir quality variation.

Dynamic coupling between cementation and porosity evolution of the Chang 8 tight sandstone reservoir, Ordos Basin: Insights from in-situ microanalysis

Understanding cement paragenesis is crucial to the study of the porosity evolution in low-permeability sandstone reservoirs. Carbon and oxygen isotope analysis with micro-drilling sampling, electron probe microanalysis, and laser Raman spectroscopy microanalysis was used to clarify the origin of cements and their relationship with reservoir quality of the Chang 8 tight sandstone reservoir in the Longdong area of the Ordos Basin. The predominant cements are chlorite, illite, kaolinite, quartz, and carbonate, which occur in 3 forms: grain rim, overgrowth, and filling of intergranular pore and intragranular dissolved pore. The quantitative paragenesis of the cements is established based on the formation temperature of cements obtained through fluid inclusion, oxygen isotope, chemical composition and Raman parameters. The main source of carbon for carbonate cements is the decarboxylation of organic matter in the adjacent mudstone interlayers. The conversion of smectite to illite and the dissolution of feldspar and previous carbonates provide Ca2+, Mg2+, and Fe3+ ions for carbonate cements and authigenic chlorite, and the authigenic chlorite rim continuously grows from the grain surface outward. The porosity reduction by the cements mainly occurs during the main hydrocarbon filling period (80–120 °C), and the reservoir belongs to the type of “hydrocarbon accumulation prior to significant porosity reduction”. This study provides a new approach for studying the temporal and spatial evolution of clastic rock diagenesis.

Three-Water Differential Parallel Conductivity Saturation Model of Low-Permeability Tight Oil and Gas Reservoirs

Addressing the poor performance of existing logging saturation models in low-permeability tight sandstone reservoirs and the challenges in determining model parameters, this study investigates the pore structure and fluid occurrence state of such reservoirs through petrophysical experiments and digital rock visualization simulations. The aim is to uncover new insights into fluid occurrence state and electrical conduction properties and subsequently develop a low-permeability tight sandstone reservoir saturation model with easily determinable parameters. This model is suitable for practical oilfield exploration and development applications with high evaluation accuracy. The research findings reveal that such reservoirs comprise three types of formation water: strongly bound water, weakly bound water, and free water. These types are found in non-connected micropores, poorly connected mesopores where fluid flow occurs when the pressure differential exceeds the critical value, and well-connected macropores. Furthermore, the three types of formation water demonstrate variations in their electrical conduction contributions. By inversely solving rock electrical experiment data, it was determined that for a single sample, the overall cementation index is the highest, followed by the cementation index of pore throats containing strongly bound water, and the lowest for the pore throats with free water. Building on the aforementioned insights, this study develops a parallel electrical pore cementation index term, ϕm′, to account for the differences among the three types of water and introduces a parallel electrical saturation model suitable for logging evaluation of low-permeability tight oil and gas reservoirs. This model demonstrated positive application effects in the logging evaluation of low-permeability tight gas reservoirs in a specific basin in the Chinese offshore area, thereby confirming the advantages of its application.

Microscopic pore-throat structure variability in low-permeability sandstone reservoirs and its impact on water-flooding efficacy: Insights from the Chang 8 reservoir in the Maling Oilfield, Ordos Basin, China

The Chang 8 reservoir of the Maling Oilfield in the Ordos Basin, China is facing a series of challenges in hydrocarbon resource development, including rapidly decreasing production rates, declining dynamic fluid levels, and elevated water cuts in oil wells, along with heterogeneity in microscopic pore-throat structures and notable interstratal inconsistencies. To systematically address these issues, this study selected representative samples from the reservoir and conducted rigorous microscopic percolation experiments on them. A comprehensive evaluation of the heterogeneity in microscopic pore structures was conducted using an integrative methodological approach, involving physical property quantification, petrographic thin-section analysis, scanning electron microscopy, constant-rate mercury intrusion, and nuclear magnetic resonance techniques. The primary objective of this investigation is to elucidate the underlying formation mechanisms, states of occurrence, and spatial distributions of residual oil. Understanding of these issues will facilitate the establishment of empirical correlations between diverse microscopic pore structures and water-flooding efficiencies, and aid in the identification of key variables governing the distribution of residual oil. Analytical outcomes reveal substantial variations in seepage characteristics contingent upon the nature of microscopic seepage conduits. Specifically, the Chang 8 reservoir manifests four discernible categories of microscopic seepage pathways: solely intergranular pores, a confluence of dissolution and intergranular pores, exclusively dissolution pores, and micropores. A correlative decline in oil displacement efficiency is observed across these conduit types. Critical variables such as throat radius and its distribution patterns emerge as pivotal determinants influencing oil displacement efficiency, eclipsing the impact of conventional physical properties and mobile fluid saturation levels. Remarkably, samples characterized by a composite of dissolution and intergranular pores demonstrate superior displacement efficiency. Distinct types of pore structures correspond to noticeably different water-flooding oil pathways and oil displacement efficiencies. During the water-flooding process, fingering network displacement is dominant, and it exerts a significant control on oil displacement efficiency. Key factors affecting this efficiency include the injected water volume multiples and displacement pressure, values of which should be optimized during the actual water-flooding process.

Production forecasting methods for different types of gas reservoirs

Hydrocarbon production in oil and gas fields generally progresses through stages of production ramp-up, plateau (peak), and decline during field development, with the whole process primarily modeled and forecasted using lifecycle models. SINOPEC's conventional gas reservoirs are dominated by carbonates, low-permeability tight sandstone, condensate, volcanic rocks, and medium-to-high-permeability sandstone. This study identifies the optimal production forecasting models by comparing the fitting coefficients of different models and calculating the relative errors in technically recoverable reserves. To improve forecast precision, it suggests substituting exponential smoothing method-derived predictions for anomalous data caused by subjective influences like market dynamics and maintenance activities. The preferred models for carbonate gas reservoir production forecasts are the generalized Weng's, Beta, Class-I generalized mathematical, and Hu-Chen models. The Vapor pressure and Beta models are optimal for forecasting the annual productivity of wells (APW) from gas-bearing low-permeability tight sandstone reservoirs. The Wang-Li, Beta, and Yu QT tb models are apt for moderate-to-small-reserves, single low-permeability tight sandstone gas reservoirs. The Rayleigh, Hu-Chen, and generalized Weng's models are suitable for condensate gas reservoirs. For medium-to-high-permeability sandstone gas reservoirs, the lognormal, generalized gamma, and Beta models are recommended.

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.

A Method for Evaluating Reservoir Permeability Based on Machine Learning Flow Unit Index

Abstract The H formation of the Y gas field in the X depression belongs to a low-permeability tight sandstone reservoir affected by sedimentation, diagenesis, and cementation. The lithology and pore structure of the target layer are complex, with strong physical heterogeneity and complex pore-permeability relationships. Conventional core pore permeability regression and nuclear magnetic resonance software-defined radio methods do not satisfy the requirements for precise evaluation in terms of permeability calculation accuracy. Based on the principle of the flow zone index (FZI) method, this study analyzed the influence of pore structure on permeability and extracted three pore structure characterization parameters, namely, the maximum pore throat radius (Rmax), displacement pressure (Pd), and average throat radius (R), from the mercury injection capillary pressure curve. The relationship between the FZI and pore structure is clarified. Therefore, the FZI in this area can characterize the permeability differences within different flow units. Based on the flow unit theory, a refined evaluation model for three types of reservoirs was established in the study area. By analyzing the response characteristics and correlation of conventional logging curves using machine learning, three optimization combination curves were selected, and a multiparameter fitting equation for the FZI was established, which was applied to predict the permeability of new wells. The results showed that the calculated permeability was highly consistent with the core analysis results, thereby providing a theoretical basis for the precise evaluation of low-permeability tight reservoirs.

Mechanical and Acoustic Response of Low-Permeability Sandstone under Multilevel Cyclic Loading-Unloading Stress Paths

Low-permeability sandstone reservoirs have been widely used as a gas storage medium worldwide. Compared with the high porosity and high permeability of sandstone, low-permeability sandstone may present different mechanical (deformation, damage or failure) and acoustic responses under cyclic loading-unloading processes caused by the high-rate injection–production of underground gas storage. In this paper, multistage triaxial loading–unloading tests with a continuously increased upper limit of stress were carried out on low-permeability sandstone under six different confining pressures. The results showed that the superposition of stress–strain curves become much denser in the process of each level of stress. Based on the variation of the elastic modulus of low-permeability sandstone under alternating loads, the mechanical behavior of low-permeability sandstone under cyclic loading is divided into three stages: cyclic hardening, stability and cyclic softening. According to the evolution of acoustic emission (AE) signal parameters, AE counts appear intensively at the initial stage of each level of stress and then gradually stabilize. The peak frequency presents the zonal distribution, which is divided into low-frequency, intermediate-frequency and high-frequency zones. Low confining pressure leads to a small b-value. The RA–AF distribution implies that the mixed tensile–shear cracks are continuously generated in low-permeability sandstone during the cyclic loading process, and the shear cracks are more obviously developed.

Fluid Identification Using XGBoost Combined with MAHAKIL in Low-Permeability Reservoirs

Summary Low-resistance reservoirs have been of great interest as a key topic in the study of low-permeability reservoirs. Accurate identification of fluid properties is a challenging problem in the effective exploration of such reservoirs. Logging data, as a common identification tool, can provide rich and highly accurate geological information. Here, we combine extreme gradient boosting (XGBoost) and MAHAKIL’s oversampling method for fluid property identification using logging data from low-permeability sandstone reservoirs. The MAHAKIL method is used to solve the class imbalance problem due to unbalanced training samples, and the data are fed into XGBoost to build a geological model with complex abstract feature weights related to fluid properties through multiple decision trees. We first demonstrate that MAHAKIL can improve the XGBoost model accuracy using four evaluation criteria, namely, the F1-score, recall, precision, and accuracy, among which the F1-score is most applicable to the classification problem of reservoir fluid prediction. Then, the receiver operating characteristic (ROC) and area under the curve (AUC) values are used to demonstrate that MAHAKIL improves the XGBoost model performance. Finally, the results and performance of this method and the traditional XGBoost model with unbalanced real data are compared. The results show that the proposed method is superior for fluid property identification in low-permeability sandstone reservoirs with imbalanced learning samples.

Integral Effects of Porosity, Permeability, and Wettability on Oil–Water Displacement in Low-Permeability Sandstone Reservoirs—Insights from X-ray CT-Monitored Core Flooding Experiments

Porosity, permeability, and wettability are crucial factors that affect the oil–water displacement process in reservoirs. Under subsurface conditions, the integral effects of these factors are extremely difficult to document. In this paper, waterflooding experiments were carried out using a core flooding system monitored with X-ray dual-energy CT. The mesoscale, three-dimensional characteristics of water displacing oil were obtained in real time. The integral effects of porosity, permeability, and wettability on the waterflooding in the low-permeability sandstone reservoirs were investigated. It was found that if the reservoir rock is water-wet, then the residual oil saturation decreases gradually with increasing porosity and permeability, showing an increasing waterflooding efficiency. On the contrary, if the reservoir rock is oil-wet, the residual oil saturation gradually increases with improving porosity and permeability, showing a decreasing waterflooding efficiency. The porosity, permeability, and wettability characteristics of reservoirs should be comprehensively evaluated before adopting technical countermeasures of waterflooding or wettability modification during oilfield development. If the porosity and permeability of the reservoir are high, water-wet reservoirs can be directly developed with waterflooding. However, it is better to make wettability modifications first before the waterflooding for oil-wet reservoirs. If the porosity and permeability of the reservoir are poor, direct waterflooding development has a better effect on oil-wet reservoirs compared with the water-wet reservoirs.

Study on SiO2 Nanofluid Alternating CO2 Enhanced Oil Recovery in Low-Permeability Sandstone Reservoirs

Study on SiO2 Nanofluid Alternating CO2 Enhanced Oil Recovery in Low-Permeability Sandstone Reservoirs

Evaluation of Tight Sandstone Mechanical Properties and Fracability: An Experimental Study of Reservoir Sand−Stones from Lufeng Sag, Pearl River Mouth Basin, Northern South China Sea

Reservoir rocks of the Pearl River Mouth Basin’s Lufeng Sag have low porosity (average porosity 12.6%) and low permeability (average permeability 16.5 mD), requiring hydraulic fracturing to obtain economic production of oil and gas. To contribute to the understanding of these reservoirs, and to promote successful production in the region, we analyzed the mechanical properties of tight sandstone. Moreover, we introduced the shear/tensile strength factor, in combination with the fracture toughness and horizontal stress difference coefficient, as an innovative approach to characterize the ease of forming a complex fracture network after reservoir fracturing. Based on this, we established a fracability evaluation model suitable for offshore low-permeability sandstone reservoirs by an analytic hierarchy process from the perspective of whether the reservoir can form an effective transformation volume and complex fracture network after fracturing. The results indicate that the primary minerals of the target reservoir are quartz and clay minerals, and the natural fractures are not developed. The mechanical properties exhibit a high Young’s modulus (ranging from 30.4 to 34.4 GPa) and high compressive strength (with cohesion between 41 and 45 MPa and an angle of internal friction between 31.0 and 33.5°). The relatively low tensile strength and fracture toughness values are conducive to fracture initiation and extension during the fracturing process. Through the fracability evaluation model constructed in this paper, the depth interval at 4155.1–4172.1 m is identified as a high-quality fractured layer. The results of this study not only provide theoretical guidance for target well and formation selection in the Lufeng Sag, but also have important practical implications for increasing oil and gas production from tight sandstone reservoirs.

Characterization of Extra Low-Permeability Conglomerate Reservoir and Analysis of Three-Phase Seepage Law

The micro distribution of residual oil in low-permeability sandstone reservoirs is closely related to pore structure, and the differences in pore structure often determine the reservoir’s productivity and development effectiveness from a macro perspective. On the basis of in-depth research, this paper analyzes the distribution law of the remaining microscopic oil, establishes the digital core multi-stage pore network modeling of the strongly sorted heterogeneous conglomerate reservoir in the Lower Wuerhe Formation of Block 8 of the Karamay Oilfield, the three-phase seepage simulation method considering the release of dissolved gas, and the three-phase permeability curve test. The research results are as follows: (1) Conventional physical property analysis shows that the permeability of core samples exhibits an inverse rhythmic distribution with layer depth. (2) CT core analysis and mercury injection experiments indicate that the area with porosity ranging from 9% to 21% accounts for 79% and is the main seepage channel area. Larger pores play an important role in seepage. (3) Through comparative experiments on cores with different permeability, it was found that the degassing phenomenon of low-permeability rock samples is more severe. In the actual process of reservoir development, it is necessary to reasonably handle the impact of water injection on development effectiveness, select appropriate water injection methods and cycles, and avoid premature water breakthrough in ultra low-permeability reservoirs.

Laboratory tests and field pilot of foam-assisted deoxidized-air flooding in a low-permeability sandstone reservoir

Foam-assisted deoxidized-air flooding is a promising technique for improving oil recovery, particularly in low-permeability oil reservoirs. However, significant differences in displacement efficiency have been observed. A comprehensive program including field pilot analysis in Wuliwan oil reservoir, a low-permeability reservoir in China, and laboratory experiments was initiated to investigate the displacement mechanism of foam-assisted deoxidized-air flooding. We carried out a series of laboratory experiments of foam-assisted deoxidized-air flooding with different gas–liquid ratios at different water cut stages, while using nuclear magnetic resonance technology to monitor the distribution of crude oil in pores. The results revealed that increasing gas–liquid ratio enhanced oil recovery during the high water cut stage, but reduced it during the middle water cut stage. The differences in oil recovery at different water cut stage appear to be linked to changes of the displacement mechanism. We indeed observed that oil was produced from a wide range of pores at the high water cut stage, but only from the macropores at the middle water cut stage. The field pilot analysis supported our conclusion based on the experimental findings, that foam-assisted deoxidized-air flooding using an appropriate gas–liquid ratio can efficiently lower water cut and enhance oil production at different water cut stages. The combination of laboratory and field pilot tests used here can serve as a template for future studies in other oil reserves.

Investigation on Invasion Depth of Fracturing Fluid during Horizontal Fracturing in Low-Permeability Oil Reservoirs with Experiments and Mathematical Models

Multistage fracturing in horizontal well has become one of the important techniques for the efficient development of low-permeability sandstone reservoirs. In multistage hydraulic fractured horizontal wells (MHFHWs), the depth of fracturing fluid invasion into the formation is a key parameter evaluating the imbibition enhancement after fracturing. However, few studies have been conducted on the invasion depth of fracturing fluids combining experiments and mathematical models under high-pressure differences in MHFHWs. Therefore, in this work, a mathematical model with experimental validation is proposed for evaluating the fracturing fluids invasion under high pressure. We first conducted a series of displacement experiments under different pressure differences to obtain the breakthrough time and invasion velocity. All core samples are taken from the block X of Xinjiang oilfield. A mathematical model of fracturing fluid injection was then established, considering the two-dimensional filtration of fracturing fluid. Then, the calculated invasion velocity was validated against the experimental data. Afterward, the invasion depth and invasion volume were determined for this typical horizontal well. Results show that at the end of 72 min, the invasion depth reaches 1.516 m when measured by core experiments and 1.434 m when calculated by the proposed model. The total invasion volume of all fracturing stages is estimated as 21,560.05 m3 and the actual total fluid volume injected is 24,019.6 m3. The paper formed a scientific and reasonable evaluation method of fracturing fluid invasion depth during the fracturing of horizontal wells, which provides solid theoretical support for the effective evaluation of fracturing to improve oil recovery.

Study on the effective methods for breaking hydrated cation bridges between crude oil and quartz

Hydrated cation bridges, in which hydrated cations connect oil and rock by hydrogen bonds, are the primary reason for crude oil adhesion on the surface of rock in low-permeability sandstone reservoirs. How to cut off hydrated cation bridges is important for higher oil washing efficiency. As a hot topic, more and more attention has been given to the study of hydrated cation bridges in recent years, but the studies mainly worked on the formation mechanism, no effective way for destroying hydrated cation bridges has been reported. In this paper, the micro influence mechanism of cation exchange, cation shielding agents and hydrogen bond disrupting agents on hydrated cation bridges was explored via molecular dynamics simulation. The replacement of Ca2+ by Na+ can effectively weaken the hydrated cation bridges by changing the structure of hydrated cations between oil and quartz and reduce the force required to peel oil droplets off quartz by 51%. Because of the interaction between cation shielding agents (AO and EDTA) and Ca2+, the appearance of cation shielding agents can affect the hydration between Ca2+ and water molecules, and reduce the force required to peel oil droplets off quartz by 37% and 4.9%. Sodium glycolate, urea and guanidine hydrochloride, which can destroy the hydrogen bond network between oil and quartz by reducing the dipole moment and polarity of water molecules, can reduce the force required to peel oil droplets off quartz by 9.5%, 19.7% and 22.0%. This research aims to explore the efficient destruction method of hydrated cation bridges and provide theoretical support for the efficient development of low-permeability sandstone reservoirs.

Experimental Investigation on Spontaneous Imbibition of Surfactant Mixtures in Low Permeability Reservoirs.

Spontaneous imbibition of surfactants could efficiently enhance oil recovery in low permeability sandstone reservoirs. The majority of studies have considered the application of individual surfactants to alter wettability and reduce interfacial tension (IFT). However, a significant synergistic effect has been reported between different types of surfactants and between salts and surfactants. Therefore, this study systematically studied the capability of a binary surfactant mixture (anionic/nonionic) and a ternary surfactant mixture (anionic/nonionic/strong base-weak acid salt) in imbibition enhanced oil recovery (IEOR). The interfacial properties and the cores' wettability were explored by IFT and contact angle measurements, respectively. Subsequently, the imbibition performances of different types of surfactant solutions were discussed. The results suggested that the surfactants' potential to enhance oil recovery followed the order of ternary surfactant mixture > binary surfactant mixture > anionic > nonionic > amphoteric > polymer. The ternary surfactant mixture exhibited strong capacity to reverse the rock surface from oil-wet (125°) to strongly water-wet (3°), which was more significant than both binary surfactant mixtures and individual surfactants. In addition, the ternary surfactant mixture led to an ultralow IFT value of 0.0015 mN/m, achieving the highest imbibition efficiency (45% OOIP). This research puts forward some new ideas on the application of the synergistic effects of surfactants in IEOR from low-permeability sandstone reservoirs.

An overview of efficient development practices at low permeability sandstone reservoirs in China

Low permeability sandstone reservoirs in China typically have more complicated geological conditions, pore structures, and flow characteristics as compared to medium-to-high-permeability sandstone reservoirs. Traditional geological and seepage theories, and engineering methods are not applicable to the development of these low permeability reservoirs, and wells drilled into them often produce oil and gas at very low rates. Recent breakthroughs in reservoir exploitation technology have greatly improved the productivity of low permeability reservoirs, making them the primary target for oil exploration and extraction in China. The development theories and practices applied to low permeability reservoirs in China are reviewed in this study— based on relevant geological and engineering practices, including drilling, fracturing, recovery, and surface engineering. A unique series of technological advances that aid the development of low permeability reservoirs in China are summarized here. This study may serve as a meaningful guide in achieving scale efficiency for the development of low permeability reservoirs.