Tight Sandstone Research Articles

Refractured Well Hydraulic Fractures Optimization in Tight Sandstone Gas Reservoirs: Application in Linxing Gas Field

Poorly producing wells in sandstone gas reservoirs are often refractured to enhance production. Considering the mutual interference of initial/refractured fractures, conductivity dynamic evolution, non-uniform inflow, and variable mass flow in the fracture comprehensively, a semi-analytical reservoir-fracture coupled production model fusing spatial and time separation methods is introduced to model refractured well performance. The proposed model is verified by CMG. The field applications indicate that the refracture job should be carried out when production is lower than the desired value. Restoring the Cf-ini and constructing the Cf-ref can increase productivity, which increases over 8 D•cm. The production growth rate just obtained a slight improvement. The production increased significantly with Lf-ini increasing from 120~270 m and Lf-ref increasing from 100~150 m. Hence, it is essential to extend the Lf-ini under engineering conditions. The ks/km = 10 can obviously increase production, but further enlarging ks does not contribute to well performance. Conversely, further producing larger bs is vital to enhancing production. Subsequently, the optimal parameter combinations (ds > Lf-ini > Lf-ref > Cf-ini > ks > Cf-ref) for well(X1) are carried out by orthogonal experiments. This work proposes a novel method to simulate refractured vertical well performance in tight gas reservoirs for refracture optimization.

Prediction method for the porosity of tight sandstone constrained by lithofacies and logging resolution

The resource potential of the Upper Triassic Yanchang Formation in the Ordos Basin is considerably large. However, owing to the low porosity and permeability, poor connectivity, and strong heterogeneity of tight sandstone, predicting the porosity of tight sandstone in this formation poses substantial challenges. The lithology of Chang 71 sub-member is dominated by arkose and lithic arkose, wherein the porosities mainly ranged between 3 and 13% and pore types were mainly feldspar dissolution pores. Based on core sample experiments and thin section analysis, combined with conventional logging curves, we proposed a three-porosity weighted average prediction method under lithological control, and a novel method for reading logging curves controlled by logging resolution is developed. We used principal component analysis to optimise the logging curves and reduce the impact of complex coupling relationships between logging curves on lithofacies identification. The stacking algorithm, which is a combination of the random forest and extreme gradient boosting models, was applied to divide the lithofacies into five categories: homogeneous-distributary-channel fine sandstone, heterogeneous-distributary-channel fine sandstone, homogeneous-mouth-bar fine sandstone, heterogeneous-mouth-bar fine sandstone, and shallow lacustrine mudstone. Compared with the results of manual classification based on logs, the accuracy of lithofacies recognition was approximately 94.2%. Additionally, sensitivity analysis of porosity curves was conducted on four types of lithofacies (i.e., except for shallow lacustrine mudstone), and porosity models for each lithofacies were established, providing an effective and objective method for the accurate prediction of porosity. This prediction method comprehensively considers sedimentary factors and incorporates statistics that are fitted using multiple linear regression, which is highly reliable. In the Chang 71 sub-member, the fitting degree between the predicted and core porosities reached 0.912, indicating that this three-porosity weighted average method based on lithofacies constraints is reasonable, reliable, and has stronger adaptability than the those reported previously. The prediction method based on lithofacies control and weight analysis can be applied to other tight sandstones, providing reliable technical support for oil and gas exploration and development.

Study on the Contribution of Different Pore Throat Sizes to Oil Displacement Efficiency in Fracture-Pore Tight Sandstone Reservoir

The pore throat and fracture system of tight sandstone reservoir are complex, the reservoir is highly heterogeneous, and the production often decreases rapidly, the development degree is low, and the development effect of water injection is poor. CO2 injection is an important means to supplement formation energy and achieve efficient reservoir development in tight reservoirs. Based on nuclear magnetic resonance technology (NMR) and high temperature and high pressure physical flow simulation experiment system, the contribution of different scales of pore throat and fracture to the improvement of oil recovery in different phases of CO2 -crude oil system is studied. The results show that the contribution of mesopores, macropores and fractures to oil displacement efficiency in the supercritical CO2 displacement stage reaches 74.58%. In immiscible CO2 displacement stage, the contribution of micropores, small pores and medium pores to oil displacement efficiency reached 73.27%. In the miscible CO2 displacement stage, the contribution of micropores and small pores to oil displacement efficiency reached 52.32%. In the supercritical CO2 displacement stage, the contribution of oil displacement efficiency is mainly provided by macropore throats and fractures. The contribution of immiscible and miscible CO2 displacement stage to oil displacement efficiency mainly comes from small pore throat with smaller scale.

Differences in reservoir quality within distributary channel belts at the braided river delta front in the Xinchang area of Western Sichuan’s 2nd member of the Xujiahe Formation: genesis and implications

AbstractThe tight sandstone reservoris are important exploration and production target in the Xujiahe Formation in Xinchang area of Western Sichuan. Due to the various lithofacies and diagenetic alteration in distributary channel belt sandstones, the reservoirs exhibit strong heterogeneity. The strong heterogeneity makes the identification of petrologically superior sandbodies a great challenge. In order to better understand reservoir quality, this study constructs a model between diagenetic alterations and reservoir quality within distributary channel belts. 73 plug samples were taken from 17 wells located in the channel belt. An integration of thin sections, X-ray diffraction, carbon and oxygen isotope ratios, cathodoluminescence, and micro-CT were analysed for the genesis and distribution of reservoir quality. The results show that subaqueous distributary channels are formed under various hydrodynamics, resulting in different lithofacies. The thicknesses of channels can be divided into less than 2 m, 2–6 m, and more than 6 m. The diagenetic alteration in lithofacies were identified. Coarse-grained sandstones with low content of rock fragments are relatively weakly compacted with less calcite and chlorite cementation. Fine-grained sandstones with high content of rock fragments are strongly compacted with calcite cementation during early diagenesis. The dissolution pores are related to the soluble mineral content and the distribution of mudstones. The subaqueous distributary channels formed in high-energy, moderate-energy, and low-energy hydrodynamic settings have experienced different diagenetic intensities. Additionally, fractures can effectively improve the reservoir properties. The distribution of good quality reservoirs is controlled by the combined influence of diagenetic heterogeneity and fractures. This would help to promote better understanding of reservoir quality within the subaqueous distributary channel belts in braided-river delta front.

Distribution law of Chang 7 Member tight oil in the western Ordos Basin based on geological, logging and numerical simulation techniques

Abstract Fine characterization of oil plane distribution in highly heterogeneous tight sandstone is a prerequisite for efficient reservoir development. This study systematically evaluated the distribution characteristics of tight oil in the Chang 7 Member of the Western Ordos Basin using a large number of experimental tests, logging interpretation, and 3D modelling methods. The logging interpretation models of shale content, porosity, permeability, and oil saturation were constructed, and the effective reservoir was identified by establishing the intersection identification pattern of reservoir acoustic wave time difference and deep lateral resistivity. The 3D numerical simulation results showed that the tight oil is distributed between injection and production wells. The areas with high tight oil content are mainly distributed along the WE direction, and a series of high remaining oil zones are formed locally. Under the influence of long-term injection and production, a high permeability zone will be formed between wells, which is similar to a high-speed channel and will be flooded quickly, and a banded remaining oil retention zone will be formed around it. For the horizontal well flooding area, the water flooding range of the water injection well is small, and a large amount of remaining oil is enriched between water injection wells. Finally, the classification standard of the remaining oil in the Chang 72 sub-member of the study area is proposed, and then, the strategy of adopting different development and adjustment schemes according to different types of reservoirs is formed.

Layered massive fracturing of carrier beds commercially unveils the deep tight sandstone gas reserves in Sichuan Basin

Achieving commercial production from deep tight gas formations poses challenges to existing geological and engineering technologies. Xujiahe tight sandstone gas, deeply buried in the Western Sichuan Basin, is proven with enormous reserves; however, preliminary hydraulic fracturing trials mostly failed to bring up the productivity. From the angle of incorporating geological and engineering knowhow, we first adopted the carrier beds theory to distinguish the favorable zones in Xujiahe Formation, then a dual sweet spot identification criterion was established based upon analytic hierarchy process, which links major geological and engineering parameters together. Provided the identified sweet spot, hydraulic fracture conductivity was then optimized to maximize the productivity. Fracturing operational parameters consisting of fluid volume and pumping, proppant size and addition, and fluid formula were then screened to secure high conductivity. Implementation of this updated geological-engineering technical route in exploiting Xujiahe tight gas reservoirs turns out to be a great success with an average gas rate of 130 Mm3/d/well during the early production stage in 14 wells. Electromagnetic monitoring further demonstrated the effectiveness of precise massive fracturing by visualizing the morphology of fracture clusters. Comparative productivity analyses manifested the breakthrough of this technical route over preceding ones in Xuejiahe gas reservoirs, providing a superior reference for discovering and developing deep tight gas resources around the world.

Seismic Facies-Controlled Porosity Prediction in a Tight Sandstone Reservoir Based on the XGBoost Algorithm

Porosity is one of the most important properties for evaluating hydrocarbon reservoirs. There is a strong nonlinearity between seismic data and rock physical properties. Machine learning methods possess the powerful ability to capture complex nonlinear relationships between these two parameters, holding significant potential for porosity prediction in tight sandstone reservoirs. In this study, we propose a seismic facies-controlled porosity prediction method based on the extreme gradient boosting algorithm. Through seismic meme inversion method,we obtain high-resolution P-impedance data. In the inversion process, lateral variations of seismic waveforms were utilized instead of the variogram function. We create labels for model training using porosity curves and borehole side P-impedance data, applying them to the extreme gradient boosting regressor. To demonstrate its feasibility, we apply the model to a real 3D case from an oil field in the Songliao Basin. Our application results demonstrate that this method can provide porosity predictions for tight sandstone reservoirs, maintaining consistency with seismic waveforms and adhering to seismic facies control patterns. The method uses only acoustic travel time, density, gamma rays, and spontaneous potential well-log data and post-stack 3D seismic data as inputs, allowing for quick porosity predictions in the field. Compared to the seismic facies-controlled inversion combined with support vector machine and multi-Layer perceptron methods, the method proposed in this study provides more reliable porosity predictions, offering insights and references for the exploration and development of tight sandstone reservoirs.

CO2 trapping dynamics in tight sandstone: Insights into trapping mechanisms in Mae Moh's reservoir

The reliance on fossil fuels is a major contributor to increased anthropogenic CO2 emissions, driving global challenges such as climate change through the greenhouse effect. Carbon capture and storage (CCS) is a promising interdisciplinary technology aimed at mitigating these emissions by securely sequestering gigatons of CO2. This study focuses on the feasibility of storing point-source CO2 emissions in saline formations, with a particular emphasis on the Mae Moh coal-fired power plant in Lampang, Thailand, which is located near its associated coal mine. The region presents challenges due to tight sandstone reservoirs buried over 2000 m deep. With reservoir simulation, this study evaluates the impact of various factors on CO2 containment and trapping in these geological settings. Results show that elevated temperatures decrease structural trapping of 43.0%–28.9% and increase solubility trapping of 28.55%–46.5%, at 40 °C and 80 °C respectively. Hysteresis is found to enhance residual trapping by immobilizing up to 31.1% of CO2 within pore spaces at 0.5. Permeability heterogeneity has a minimal impact on overall trapping efficiency due to the less heterogeneity of the tight sandstone. However, the kV/kH ratio significantly influences vertical CO2 migration which resulted in residual trapping at its highest at the ratio of 0.1, while lower ratios support lateral dispersion. Moderate rock compressibility values are identified as optimal for structural and residual trapping, while extreme compressibility enhances solubility trapping by up to 30%. These findings emphasize the complexity of CO2 trapping mechanisms in tight sandstone formations, emphasizing the need for careful consideration of key factors in CCS projects.

Mechanisms of Proppant Transport in Rough Fractures of Offshore Unconventional Reservoirs: Shale and Tight Sandstone

After hydraulic fracturing, unconventional reservoirs frequently encounter challenges related to limited effective proppant support distance and suboptimal proppant placement. Due to the strong heterogeneity of offshore reservoirs, which causes varying fracture roughnesses depending on different lithologies, a systematic study of the relationship between roughness and proppant transport could optimize operational parameters. This study incorporates the box dimension method for fractal dimension analysis to quantify roughness in auto-correlated Gaussian distributed surfaces created by true triaxial tests. Combined with the numerical analysis of (computational fluid dynamics) CFD-DEM (discrete element method) for bidirectional coupling, the laws of proppant deposition and transport processes within fractures with different roughnesses are obtained through comparative verification simulations. The results show that for rougher fractures of shale, the proppants are transported farther, but at JRC_52, (joint roughness coefficient), where there may be plugging in curved areas, there is a risk of near-well blockages. Compared to the smooth model, fluctuations in JRC_28 (tight sandstone) drastically increase turbulent kinetic energy within the fracture, altering particle transport dynamics. Moreover, smaller proppants (d/w ≤ 0.3) exhibit better transport capacity due to gravity, but the conductivity of the proppant is limited when the particles are too small. A d/w of 0.4 is recommended to guarantee transport capacity and proppant efficiency near the well. Additionally, proppants injected sequentially from small to large in shale fractures offer optimal propping effects, and can take advantage of the better transport capacity of smaller proppants in rough fractures. The large proppant (d/w = 0.8) is primarily deposited by gravity and forms a sloping sand bed, which subsequently ensures the aperture of the fractures. This research provides a fresh perspective on the influence of fracture roughness on proppant transport in offshore unconventional reservoirs and offers valuable considerations for the order of proppant injection.

Quantitative classification evaluation model for tight sandstone reservoirs based on machine learning

Tight sandstone reservoirs are a primary focus of research on the geological exploration of petroleum. However, many reservoir classification criteria are of limited applicability due to the inherent strong heterogeneity and complex micropore structure of tight sandstone reservoirs. This investigation focused on the Chang 8 tight reservoir situated in the Jiyuan region of the Ordos Basin. High-pressure mercury intrusion experiments, casting thin sections, and scanning electron microscopy experiments were conducted. Image recognition technology was used to extract the pore shape parameters of each sample. Based on the above, through grey relational analysis (GRA), analytic hierarchy process (AHP), entropy weight method (EWM) and comprehensive weight method, the relationship index Q1 between initial productivity and high pressure mercury injection parameters and the relationship index Q2 between initial productivity and pore shape parameters are obtained by fitting. Then a dual-coupled comprehensive quantitative classification prediction model for tight sandstone reservoirs was developed based on pore structure and shape parameters. A quantitative classification study was conducted on the target reservoir, analyzing the correlation between reservoir quality and pore structure and shape parameters, leading to the proposal of favourable exploration areas. The research results showed that when Q1 ≥ 0.5 and Q2 ≥ 0.5, the reservoir was classified as type I. When Q1 > 0.7 and Q2 > 0.57, it was classified as type I1, indicating a high-yield reservoir. When 0.32 < Q1 < 0.47 and 0.44 < Q2 < 0.56, was classified as type II. When 0.1 < Q1 < 0.32 and 0.3 < Q2 < 0.44, it was classified as type III. Type I reservoirs exhibit a zigzag pattern in the northwest part of the study area. Thus, the northwest should be prioritized in actual exploration and development. Additionally, the initial productivity of tight sandstone reservoirs showed a positive correlation with the porosity, permeability, sorting coefficient, coefficient of variation, and median radius. Conversely, it demonstrated a negative correlation with the median pressure and displacement pressure. The perimeters of pores, their circularity, and the length of the major axis showed a positive correlation with the porosity, permeability, sorting coefficient, coefficient of variation, and median radius. On the other hand, they exhibited a negative correlation with the median pressure and displacement pressure. This study quantitatively constructed a new classification and evaluation system for tight sandstone reservoirs from the perspective of microscopic pore structure, achieving an overall model accuracy of 93.3%. This model effectively predicts and evaluates tight sandstone reservoirs. It provides new guidance for identifying favorable areas in the study region and other tight sandstone reservoirs.

Research on the Migration and Settlement Laws of Backflow Proppants after Fracturing Tight Sandstone

This article studies the migration and settlement laws of backflow proppants after fracturing tight sandstone. This paper proposes a fitting method based on a multi-task learning network to address the issue of interference from multiple physical parameters during the transport and settlement processes of proppants. This method can effectively handle multi-dimensional interference factors and fit the mapping logic of multiple engineering parameters to transport patterns through the continuous correction of multi-layer networks. We first introduce the characteristics of tight sandstone reservoirs and their important value in mining, as well as the status of current research on the migration and settlement laws of proppants at home and abroad. Based on this, we then deeply analyze the sedimentation rate model of proppants in tight sandstone backflow and the equilibrium height of proppants under multiple factors of interference while considering the distribution characteristics of proppants. In order to more accurately simulate the transport and settlement laws of proppants, this paper introduces a multi-task learning network. This network can comprehensively consider multi-dimensional parameters, learn the inherent laws of data through training, and achieve accurate fitting of the transport and settlement laws of proppants. This study trained and tested the model using actual production data, and the results showed that the proposed model can fit the input–output relationship well, thus effectively supporting the study of proppant transport and settlement laws.

Study on dynamic imbibition mechanism of matrix-fracture in three dimensions tight sandstone based on level set method

Tight oil reservoirs require fracturing techniques to create complex fracture networks for efficient development. It is frequently accompanied by a dynamic matrix-fracture imbibition process, promoting enhanced recovery. At present, the mechanism of three dimensions (3D) matrix-fracture dynamic imbibition at the pore scale has not been fully elucidated. In this paper, the dynamic imbibition process of oil-water two phases in matrix-fracture was simulated based on the Navier–Stokes equations, and the level set method was used to capture the real-time interfacial changes between the two phases. It was found that during matrix-fracture dynamic imbibition process, oil-phase droplets in a single pore remain in the pore mainly due to the “stuck” effect. Cluster residual oil in the pore space is mainly retained due to the “flow around” effect. Continuous residual oil in the deeper regions of the matrix is due to insufficient capillary force. Water phase in the micro-confinement space of a tight reservoir intrudes into the pore space along the pore corners, forming the “fingering” phenomenon is beneficial for enhancing the efficiency of micro-dynamic imbibition. It differs from cognition obtained in the micro-view space during conventional water flooding. The enhancement of imbibition efficiency is often accompanied by the occurrence of fluctuations in the average pressure within the matrix. Therefore, a method involving impulse type of high-frequency and short-period for supplemental energy and imbibition is suggested to enhance recovery in tight sandstone reservoirs. This study reveals the detailed mechanisms of oil-water two-phase transport at different stages in the dynamic imbibition process and holds significant guiding implications for enhancing recovery in this type of reservoirs.

Feasibility of CO2 storage and enhanced gas recovery in depleted tight sandstone gas reservoirs within multi-stage fracturing horizontal wells

Injecting CO2 when the gas reservoir of tight sandstone is depleted can achieve the dual purposes of greenhouse gas storage and enhanced gas recovery (CS-EGR). To evaluate the feasibility of CO2 injection to enhance gas recovery and understand the production mechanism, a numerical simulation model of CS-EGR in multi-stage fracturing horizontal wells is established. The behavior of gas production and CO2 sequestration is then analyzed through numerical simulation, and the impact of fracture parameters on production performance is examined. Simulation results show that the production rate increases significantly and a large amount of CO2 is stored in the reservoir, proving the technical potential. However, hydraulic fractures accelerate CO2 breakthrough, resulting in lower gas recovery and lower CO2 storage than in gas reservoirs without fracturing. Increasing the length of hydraulic fractures can significantly increase CH4 production, but CO2 breakthrough will advance. Staggered and spaced perforation of hydraulic fractures in injection wells and production wells changes the fluid flow path, which can delay CO2 breakthrough and benefit production efficiency. The fracture network of massive hydraulic fracturing has a positive effect on the CS-EGR. As a result, CH4 production, gas recovery, and CO2 storage increase with the increase in stimulated reservoir volume.

Characteristics, main controlling factors and densification mechanisms of unconventional tight reservoirs in Triassic Yanchang Formation in southern Ordos Basin, China

The key factors controlling the densification of unconventional reservoirs (e.g., tight oil and gas reservoirs) remain poorly understood and directly affect the distribution of exploitable resources. Here, systematically explored reservoir characteristics, depositional microfacies, and the main factors controlling densification of the tight oil reservoir in the Chang 8 Member (Yanchang Formation, Middle Triassic) in the Zhenjing area of the southern Ordos Basin by thin section analysis, scanning electron microscopy, physical property measurement, X-ray diffraction, and mercury injection. Our results confirm the Chang 8 reservoir as an extremely low permeability tight sandstone reservoir mainly comprising lithic feldspathic sandstone with various primary and secondary pores and fine pore channels. The highest quality reservoir is mainly restricted to the middle and lower parts of subaqueous distributary channel microfacies. Dissolution partly contributed to reservoir formation, but the persistence of early, non-compressed storage space was more important. The compression of plastic rock debris removed a significant amount of porosity, and calcite and kaolinite both fill pores and contribute to the structural strength of pore space. We identified three densification processes: the persistent densification of highly plastic rocks, calcite cementation, and feldspar dissolution and subsequent kaolinite precipitation. After their compaction, the Chang 8 Member reservoirs were charged with hydrocarbons. We applied clustering analysis to eight reservoir characteristics (porosity, permeability, median pore-throat radius, maximum pore-throat radius, median capillary pressure, pore discharge pressure, chlorite content, kaolinite content) to quantitatively classify the Chang 8 reservoir into three categories. Type-I reservoirs have the best conditions for hosting tight oil reservoirs, with ∼12% porosity, permeabilities of ∼0.2 × 10−3 μm2, trial oil production rates of >5 m3/d, and, indeed, occur in subaqueous distributary channel microfacies. Type-II reservoirs ∼10% porosity, permeabilities of ∼0.1 × 10−3 μm2, and trial oil production rates of 1–5 m3/d. Type-III reservoirs have ∼5% porosity, permeabilities of ∼0.05 × 10−3 μm2, and trial oil production rates <1 m3/d. These results provide an important basis for predicting the distribution of exploitable zones in the Chang 8 sandstone and other adjacent tight sandstones.

Adsorption and retention of fracturing fluid and its impact on gas transport in tight sandstone with different clay minerals

To elucidate the adsorption characteristics and retention mechanisms of fracturing fluids in diverse clay minerals, we conducted on-line nuclear magnetic resonance (NMR) and atomic force microscopy (AFM) experiments. The depth and extent of solid phase damage are determined by the ratio between the size of fine fractions in fracturing fluid residue and the pore-throat size in experiments. Poor physical properties (K < 0.5 mD) result in a more preferential flow pathway effect during flowback, and the stepwise incremental pressure differential proves to be more effective for the discharge of fracturing fluid in submicron pore throats. The permeability is significantly influenced by the differential distribution of retained fracturing fluid, as supported by direct experimental evidence. The presence of good physical properties (K > 0.5 mD) combined with a scattered distribution of retained fracturing fluid is associated with high gas phase recovery permeability, whereas a continuous sheet-like distribution results in low recovery permeability. The expansive surface area and presence of filamentous illite minerals facilitate the multiple winding and adsorption of fracturing fluids, demonstrating strong hydrogen-bonding, multi-layering and multiple adsorption properties. The geological characteristics of the main gas formations exhibit significant variation, and the severity of damage caused by fracturing fluids occurs in diverse sequences. To address this issue, a differentiated strategy for optimizing fracturing fluids has been proposed.

Modelowe i empiryczne podejście do oceny parametrów petrofizycznych skał na przykładzie złoża gazu Dhodak w Pakistanie

The main aim of the presented study was to perform an analysis of petrophysical rock parameters for the Pab Formation, which is a potential reservoir, located at four-depth intervals within the Dhodak Gas Field. The Pab Formation in the studied wells is mostly composed of the well-sorted sandstone. The intervals for the study were selected by applying a gamma ray log cut-off of 40%. A Matlab code that is user-friendly and contains empirical and numerical models (Raymor’s, Han's, Castagna’s, Jizba, Blangy, and Gardner's models) was designed with the purpose of providing an interpretation of rock physics parameters in reservoirs. The results indicate that the Pab Formation is mainly saturated with hydrocarbons and possesses sufficient porosity (i.e. between 8 and 38%). According to the cross-plot models, there are a few zones within the Pab Formation that are weakly consolidated. These zones are located at depths of 2377–2404 m and 2418–2430 m. However, the same area is classified as tight gas sandstone and is located between 2330 to 2343 m. The results of the study indicate that the Pab Formation is potentially saturated with hydrocarbons. These findings were based on structural and rock physics assessments of the study area. The approach presented in this work is also helpful for structural trap evaluation. In addition, the petrophysical rock parameter models developed can contribute to reducing the risks associated with hydrocarbon exploration, enabling accurate representation of subsurface conditions and improving reservoir forecasting capabilities in oil producing areas.

Characteristics and effectiveness of deep and ultradeep tight sandstone fractures: Insights from geologic and geophysical data analysis

Effective natural fractures are those that contribute to reservoir storage and conductivity. In this study, the effectiveness of fractures in deep and ultradeep reservoirs (depths &gt; 6 km) is evaluated by using geophysical image logs, cores, microstructures, mechanical tests, and geologic evidence of the tectonic context (including current in situ stress) and sedimentary faces and diagenesis. Intraformational open-mode fractures are the most common fracture type in this tectonically active region, and their effectiveness is affected by the coupling between past tectonic activity, in situ stress, and chemical reactions such as mineral precipitation or dissolution (diagenesis). Our results show that the effectiveness of fractures is mainly related to the aperture and filling, and fractures formed by early tectonic movement are more likely to be filled by minerals, reducing their effectiveness. Strata near orogenic belts in strongly cemented, tight diagenetic facies exhibit a greater abundance of mineral-filled fractures, whereas dissolution increases the fracture apertures, produces secondary pores in host rocks, and roughens the fracture walls. The effective normal stress acting on the fracture surface decreases when the fracture is parallel to the maximum horizontal stress component, so the fracture has a large aperture and, therefore, is more effective. The results of our laboratory measurements reveal that the contribution of fractures to the reservoir space is limited, and the reservoir space provided by fractures accounts for only 13% of all types of reservoir space, whereas the presence of fractures increases reservoir permeability by 1–2 orders of magnitude. Fractures improve the effectiveness of the reservoir by connecting the dispersed pores in the reservoir matrix. Fractures with a low angle to the maximum horizontal stress component have greater apertures and permeabilities and are the main channels for fluid flow.

Natural gas accumulation conditions and exploration directions of Carboniferous clastic rocks in the northeastern margin of Junggar Basin, China

The Carboniferous strata in the northeastern Junggar Basin are an important exploration field for natural gas in the basin. However, volcanic rocks have long been the primary exploration target. In contrast, the exploration and research of clastic rocks associated with source formations have been largely overlooked, resulting in an insufficient understanding of the reservoir forming conditions and exploration potential of Carboniferous clastic rocks. Through the evaluation of Carboniferous source rocks, effective source stove characterization, clastic reservoir evaluation, oil and gas source correlation, and reservoir formation model construction in this region, three key findings have been made. First, the Carboniferous in the northeastern Junggar Basin has developed three sets of high-quality gas source rocks: the Dishuiquan Formation, the Songkalsu B Member, and the Shiqiantan Formation. These formations correspond to three hydrocarbon source centers: the Sannan–Dishuiquan Sag, the Wucaiwan Sag–Dajing area, and the Dongdao Haizi Sag–Baijiahai High. Second, the Carboniferous system in the northeast has developed multiple types of large-scale reservoirs, including sand conglomerates, sandstones, turbidites, dolomitic rocks, and shale. These reservoirs are generally characterized by low porosity to ultra-low porosity and low permeability to ultra-low permeability reservoirs. There is a dissolution pore development zone at depths of 2900–4500 m. Third, a comparison of oil and gas sources reveals that all three sets of gas source rocks contribute to the natural gas found in the northeast, with obvious characteristics of near-source reservoir formation. The Carboniferous clastic rocks host two types of natural gas reservoirs: unconventional and conventional near-source reservoirs. It is predicted that there is an orderly accumulation pattern of shale gas, tight sandstone gas, and conventional natural gas reservoirs. This study reveals that the Carboniferous clastic rock source and reservoir configuration in the northeastern Junggar Basin is highly favorable, and the natural gas reservoirs in source and near-source clastic rocks represent important exploration directions.

Saturation Prediction of Specific Tight Sandstone Reservoirs Based on Experimental Analysis of Oil-Water Relative Permeability

Saturation Prediction of Specific Tight Sandstone Reservoirs Based on Experimental Analysis of Oil-Water Relative Permeability

Control of lamination on bedding-parallel fractures in tight sandstone reservoirs: the seventh member of the upper Triassic Yanchang Formation in the Ordos Basin, China

Control of lamination on bedding-parallel fractures in tight sandstone reservoirs: the seventh member of the upper Triassic Yanchang Formation in the Ordos Basin, China