Search Results (84)

Unconventional hydrocarbon reservoirs with low matrix permeability (<0.3 mD), high temperatures, and sour conditions present significant challenges for stimulation and production enhancement. This study examines field trials for a large oil and gas operator in the UAE, focusing on tight carbonate deposits with reservoir temperatures above 93 °C and high sour gas content. A novel multi-stage chemical stimulation workflow was created, beginning with a pre-flush phase that alters rock wettability and reduces interfacial tension at the micro-scale. This was followed by a second phase that increased near-wellbore permeability and ensured proper acid placement. The treatment’s core used a thermally stable, corrosion-resistant retarded acid system designed to slow reaction rates, allow deeper acid penetration, and build prolonged conductive wormholes. Simulations revealed considerable acid penetration of the formation beyond the near-wellbore zone. The post-treatment field data showed a tenfold improvement in injectivity, which corresponded closely to the acid penetration profiles predicted by modeling. Furthermore, oil production demonstrated sustained, high oil production of 515 bpd on average for several months after the treatment, in contrast to the previously unstable and low-rate production. Finally, the findings support a reproducible and technologically advanced stimulation technique for boosting recovery in ultra-tight carbonate reservoirs using the acid retardation effect where traditional stimulation fails. Full article

This study systematically analyzes reservoir formation mechanisms under deep burial conditions, integrating macroscopic observations from representative ultra-deep clastic reservoirs in four major sedimentary basins in central and western China. Developing effective clastic reservoirs in ultra-deep strata (6000–8000 m) remains a critical yet debated topic in petroleum geology. Recent advances in exploration techniques and geological understanding have challenged conventional views, confirming the presence of viable clastic reservoirs at such depths. Findings reveal that reservoir quality in ultra-deep strata is preserved and enhanced through the interplay of sedimentary, diagenetic, and tectonic processes. Key controlling factors include (1) high-energy depositional environments promoting primary porosity development, (2) proximity to hydrocarbon source rocks enabling multi-phase hydrocarbon charging, (3) overpressure and low geothermal gradients reducing cementation and compaction, and (4) late-stage tectonic fracturing that significantly improves permeability. Additionally, dissolution porosity and fracture networks formed during diagenetic and tectonic evolution collectively enhance reservoir potential. The identification of favorable reservoir zones under the sedimentation–diagenesis-tectonics model provides critical insights for future hydrocarbon exploration in ultra-deep clastic sequences. Full article

Granite is widely regarded as an ideal material for the construction of underground liquefied natural gas (LNG) storage reservoirs due to its high mechanical strength and broad geological availability. However, the ultra-low storage temperature of LNG (−162 °C) poses potential risks in altering the permeability of granite, which may compromise the long-term safety and integrity of the reservoir. To investigate the permeability characteristics and microstructural degradation of granite under low-temperature conditions, both coarse-grained and fine-grained granite samples were subjected to a series of experiments, including one-dimensional (1D) gas permeability tests (conducted before and after freeze–thaw cycles ranging from −20 °C to −120 °C), nuclear magnetic resonance (NMR) tests, and two-dimensional (2D) gas permeability tests performed under real-time low-temperature conditions. Experimental results indicated that the gas permeability of granite under real-time low-temperature conditions exhibited a linear increase as the temperature decreased. In contrast, the gas permeability after freeze–thaw cycling followed a nonlinear trend: it increased initially, plateaued, and then increased again as the freezing temperature continued to drop. A further analysis of pore structure evolution and permeability changes revealed distinct degradation mechanisms depending on grain size. In coarse-grained granite, freeze–thaw damage was primarily characterized by the initiation and propagation of new microcracks, which originated as micropores and expanded into mesopores. In fine-grained granite, the damage primarily resulted from the progressive widening of existing fissures, with micropores gradually evolving into mesopores over successive cycles. The study’s findings provide a useful theoretical foundation for the secure subterranean storage of LNG. Full article

The Wufeng–Longmaxi formations in the Sichuan Basin have emerged as China’s principal shale gas exploration target, with drilling results confirming substantial resource potential. Although the Neijiang–Rongchang Block demonstrates promising production, significant performance variations among lithofacies and reservoir types highlight the need for enhanced understanding of reservoir evolution. This study integrates petrological analyses, SEM imaging, XRD characterization, seismic interpretation, and production data from multiple wells targeting the Wufeng–Long 1-1 Sub-member. Key insights reveal the following: (1) reservoir lithology consists predominantly of siliceous shale (68% occurrence), characterized by high quartz content (48% avg), low carbonates (<15%), and low clay (<30%); (2) organic-rich intervals contain Type I kerogen derived from planktonic algae, with thermal maturity indicating post-mature evolution; (3) premium reservoirs develop multi-scale pore networks combining organic-hosted pores, interparticle pores, and micro-fractures. Despite high brittle mineral content, mechanical competence decreases stratigraphically from the Wufeng Formation (78%) to Long 1-1⁷ (63%); (4) depositional redox conditions facilitated exceptional organic preservation. Core analyses reveal low porosity (5.5% avg) and ultra-low permeability (0.27 × 10⁻³ μm² avg), classifying reservoirs as multiple tight unconventional systems in the study area. The proposed lithofacies-controlled pore evolution model elucidates reservoir heterogeneity mechanisms, providing critical geological criteria for optimized shale gas development. Full article

The eighth member of the Permian Shihezi Formation is one of the main tight sandstone gas layers in the Longdong Area of Ordos Basin, and the source rocks are dark mudstones and shales located in the Shanxi Formation and Taiyuan Formation of the Permian. The tight muddy sandstone at the top provides shielding conditions and constitutes traps. The lithology is mainly lithic quartz sandstone, followed by lithic sandstone. The reservoir space is mainly dissolved pores, inter crystalline pores, intergranular pores and so on. Clay minerals are the main interstitial materials, and chlorite has the highest content in it, a product of alkaline, moderate- to high-temperature, reducing conditions, effectively inhibited quartz cementation and enhanced secondary porosity development during mesodiagenesis. The average porosity of the reservoir is about 4.01%, and the average permeability is about 0.5 × 10⁻³ μm³, which is a typical low porosity and ultra-low permeability tight reservoir. The thickness of the sandstone reservoir in the study area is from 5 m to more than 25 m, mainly in the NE direction. The sand bodies are distributed in lenses on the plane. Full article

Tight sandstone gas reservoirs, characterized by low porosity (typically < 10%) and ultra-low permeability (commonly < 0.1 × 10⁻³ μm²), represent a critical transitional resource in global energy transition, accounting for over 60% of total natural gas production in regions such as North America and Canada. In the northern Tianhuan Depression of the Ordos Basin, the Permian He 8 Member (He is the abbreviation of Shihezi) of the Shihezi Formation serves as one of the primary gas-bearing intervals within such reservoirs. Dominated by quartz sandstones (82%) with subordinate lithic quartz sandstones (15%), these reservoirs exhibit pore systems primarily supported by high-purity quartz and rigid lithic fragments. Diagenetic processes reveal sequential cementation: early-stage quartz cementation provides a framework for subsequent lithic fragment cementation, collectively resisting compaction. Depositionally, these sandstones are associated with fluvial-channel environments, evidenced by a sand-to-mud ratio of ~5.2:1. Pore structures are dominated by intergranular pores (65%), followed by dissolution pores (25%) formed via selective leaching of unstable minerals by acidic fluids in hydrothermal settings, and minor intragranular pores (10%). Authigenic clay minerals, predominantly kaolinite (>70% of total clays), act as the main interstitial material. Reservoir properties average 7.01% porosity and 0.5 × 10⁻³ μm² permeability, defining a typical low-porosity, ultra-low-permeability system. Vertically stacked sand bodies in the He 8 Member display large single-layer thicknesses (5–12 m) and moderate sealing capacity (caprock breakthrough pressure > 8 MPa), hosting gas–water mixed-phase occurrences. Rock mechanics experiments demonstrate that fractures enhance permeability by >60%, significantly controlling reservoir heterogeneity. Full article

The geological structure of interbedded shale oil reservoirs is complex, later characterized by high reservoir heterogeneity and diverse reservoir spaces. These distinctive features are primarily attributed to their unique source–storage configuration. This paper comprehensively investigates the pore structure characteristics and controlling factors, which are beneficial for realizing efficient and sustainable resource utilization. The pore structure characteristics and main control factors of interbedded shale oil in the Heshuinan (HSN) area of the Ordos Basin are studied by analyzing thin sections and scanning them under an electron microscope, and using XRD analysis, a high-pressure mercury injection, a constant-rate mercury injection, and a nitrogen adsorption method. The influence of sedimentation and diagenesis on the pore structure is analyzed. Research shows that the interbedded shale oil reservoirs of the Triassic Chang 7 in the HSN area have an average porosity of 8.47% and an average permeability of 0.74 × 10⁻³ μm². The reservoirs are classified as typical ultra-low porosity, ultra-low permeability reservoirs. The various pore types in the study area are mainly residual intergranular pores and feldspar dissolution pores. The pores are mostly in the shape of parallel slits and ink-bottle-shaped. The pore-throat radii range from 0.02 μm to 200 μm. Sedimentation and diagenesis jointly control the pore structure in the study area. Sedimentation determines the material foundation of the study area. Diagenesis affects later pore development. Early compaction greatly reduces the intergranular pores, but the chlorite envelope reduces the influence of compaction to some extent. The compacted residual intergranular pores are further reduced by clay minerals, carbonate minerals, and siliceous minerals. Late dissolution promotes pore enlargement, which is the key to the formation of high-quality reservoirs. Furthermore, on this basis, this paper outlines the genetic mechanism of the Chang 7 high-quality reservoir in the HSN area to provide guidance for the exploration and development of interbedded shale oil and gas. Full article

The impact of anthropogenic disturbances during reservoir development on the ecological system—encompassing both environmental and microbial components—has long been overlooked. This study pioneers the investigation into the effects of microbially activated water flooding on both reservoir environments and indigenous microbial communities. We conducted a comprehensive analysis of the B9 Reservoir’s parameters before and after field testing, including the pH, redox potential, conductivity, chemical oxygen demand, biochemical oxygen demand, aqueous-phase cell concentration, aqueous-phase deoxyribonucleic acid (DNA) concentration, oil-phase DNA concentration, and microbial population data. The results demonstrate that environmental parameters exhibit high sensitivity to microbially activated water flooding and effectively explain microbial blooms, while microbial blooms reciprocally alter the environmental conditions, forming a mutually influencing dynamic interplay. The 183-day microbially activated water flooding, while causing detectable impacts on the reservoir environment and microorganisms, did not pose a threat to its ecological stability and contributed to enhanced oil production. In contrast, the 60-month pilot test concluded 27 months earlier exhibited potential destabilization risks to the reservoir ecology. By simultaneously monitoring reservoir environments and microbial dynamics, this research not only addresses potential ecological risks associated with human-driven reservoir development but also provides actionable insights to optimize reservoir management strategies. Full article

Shale oil is abundant in geological reserves, but its recovery rate is low due to its unique characteristics of ultra-low porosity, ultra-low permeability, and high clay content. This study investigated the effect of mixed-charge surfactants (PSG) on enhanced oil recovery (EOR) in high-temperature shale reservoirs, building on our previous research. The results indicate that PSG not only has outstanding interfacial activity, anti-adsorption, and high-temperature resistance but can also alter the wettability of shale. After aging at 150 °C for one month, a 0.2% PSG solution exhibited minimal influence on the viscosity reduction and oil-washing properties but significantly altered the oil/water interfacial tension (IFT). Compared to field water, the 0.2% PSG solution enhances the static oil-washing efficiency by over 25.85% at 80 °C. Moreover, its imbibition recovery rate stands at 29.03%, in contrast to the mere 9.84% of field water. Because of the small adhesion work factor of the PSG solution system, it has a strong ability to improve shale wettability and reduce oil/water IFT, thereby improving shale oil recovery. This study provides the results of a laboratory experiment evaluation for enhancing shale oil recovery with surfactants. Furthermore, it holds significant potential for application in the single-well surfactant huff-n-puff process within shale reservoirs. Full article

Understanding the changes in the pore structure of reservoirs in the presence of CO₂ is critical for carbon neutrality, especially for shale oil reservoirs with ultra-low permeability and porosity. However, studies examining the alteration in the pore structure of shale oil reservoirs that have been treated with CO₂ remain limited. Thus, in this paper, nuclear magnetic resonance (NMR) and low-temperature nitrogen adsorption (LNA) technologies were employed to address this issue. The results show that the permeability and porosity of shale oil reservoirs increase after exposure to CO₂. The permeability improves by 49.03%, and the porosity increases by 29.54%. The NMR results reveal that the pore structure of shale oil reservoirs is altered. Specifically, increases of 11.14%, 74.54%, and 990.02% in the presence of CO₂ are observed for micropores, mesopores, and macropores, respectively. CO₂ is more sensitive to macropores, followed by mesopores and micropores. Furthermore, the LNA results indicate that some small pores expand into larger pores, leading to a decrease in the number of small pores and an increase in the number of larger pores. Combining the results of NMR and LNA, it is found that the increase in big pores is the reason behind the enhancement in permeability and porosity. This paper sheds light on the change in the pore structure of shale oil reservoirs after exposure to CO₂, further guiding the evaluation of CO₂ storage capacity. Full article

High-pressure low-permeability gas reservoirs have a complex gas–water distribution, a lack of a unified gas–water interface, and widespread water intrusion in localized high areas, which seriously constrain sweet spot prediction and development deployment. In this study, the high-pressure, low-permeability sandstone of Huangliu Formation in Yinggehai Basin is taken as the object, and the micro gas–water distribution mechanism and the main controlling factors are revealed by combining core expulsion experiments and COMSOL two-phase flow simulations. The results show that the gas saturation of the numerical simulation (20 MPa, 68.98%) is in high agreement with the results of the core replacement (66.45%), and the reliability of the model is verified. The natural gas preferentially forms continuous seepage channels along the large pore throats (0.5–10 μm), while residual water is trapped in the small throats (<0.5 μm) and the edges of the large pore throats that are not rippled by the gas. The breakthrough mechanism of filling pressure grading shows that the gas can fill the 0.5–10 μm radius of the pore throat at 5 MPa, and above 16 MPa, it can enter a 0.01–0.5 μm small throat channel. The distribution of gas and water in the reservoir is mainly controlled by the pore throat structure, formation temperature, and filling pressure, and the gas–liquid interfacial tension and wettability have weak influences. This study provides a theoretical basis for the prediction of sweet spots and optimization of development plans for low-permeability gas reservoirs. Full article

The fluid action mechanism and diagenetic evolution of tuff reservoirs in the Cretaceous Huoshiling Formation of the Dehui fault depression are discussed herein. The fluid properties of the diagenetic flow are defined, and the pore formation mechanism of the reservoir space is explained by means of thin sections, X-ray diffraction, electron probes, scanning electron microscopy (SEM), cathodoluminescence, and stable carbon and oxygen isotopic composition and fluid inclusion tests. The results reveal that the tuff reservoir of the Huoshiling Formation is moderately acidic, and the physical properties of the reservoir are characterized by middle to high porosity and ultralow permeability. The pore types are complex, comprising both primary porosity and secondary porosity, with dissolution pores and devitrification pores being the most dominant. Mechanical compaction and cementation are identified as key factors reducing reservoir porosity and permeability, while dissolution and devitrification processes improve pore structure and enhance pore connectivity. Diagenetic fluids encompass alkaline fluids, acidic fluids, deep-seated CO₊-rich hydrothermal fluids, and hydrocarbon-associated fluids. These fluids exhibit dual roles in reservoir evolution: acidic fluids enhance the dissolution of feldspar, tuffaceous materials, and carbonate minerals to generate secondary pores and improve reservoir quality, whereas alkaline fluids induce carbonate cementation, and clay mineral growth (e.g., illite) coupled with late-stage mineral precipitation obstructs pore throats, reducing permeability. The interplay among multiple fluid types and their varying dominance at different burial depths collectively governs reservoir evolution. This study underscores the critical role of fluid–rock interactions in controlling porosity–permeability evolution within tuff reservoirs. Full article

Injecting liquid into the formation has an impact on the microstructure of the reservoir and formation fluids, and negative effects often lead to the failure of oil well stimulation measures to achieve the expected results. It is crucial to clarify the reasons for the decrease in the injection capability of low-permeability reservoirs in China and the mechanisms of the impact of on-site injection water quality. This study first conducted injection experiments with different water qualities. To study the micro factors that cause damage, clay mineral X-ray diffraction (XRD) analysis, high-pressure mercury injection experiments before and after damage, nuclear magnetic resonance (NMR) during the damage process, scanning electron microscopy (SEM) after damage, and energy dispersive spectroscopy elemental spectrum analysis (EDS) of incompatible sediment were carried out on the experimental core. In injection experiments with different water qualities, the permeability decreased by up to 65.35% when the injection volume reached 60 PV. The main causes of the decrease in injection capability are poor reservoir porosity and permeability and formation particle blockage. The particles mainly come from suspended particles, emulsified oil, migration of formation particles, and sediment formed by the injected water. This paper also proposes a reference for water quality index optimization in similar reservoirs. The new water quality index reduced permeability damage by at least 3.22%. Full article

In China, most medium- and shallow-depth coalbed methane (CBM) reservoirs are in the middle to late stages of development. Exploiting CBM in unsaturated low-permeability reservoirs remains particularly challenging. This study investigates the evolution of reservoir pressure in rock strata during CBM extraction from a low-permeability coal seam in the Ordos Basin. By integrating the seepage equation, material balance equation, and fluid pressure theory, we establish a theoretical and numerical model of reservoir pressure dynamics under varying bottom-hole flowing pressures. The three-dimensional surface of reservoir pressure is characterized by the formation of a stable pressure drop funnel. The results show that gas–liquid flow capacity is significantly constrained in low-permeability reservoirs. A slower drainage control rate facilitates the formation of stable seepage channels and promotes the expansion of the seepage radius. Under ultra-low permeability (0.5 mD) to low permeability (2.5 mD) conditions, controlling the bottom-hole flowing pressure below the average value aids the effective expansion of the pressure drop funnel. Numerical simulations indicate that the seepage and desorption radii expand more effectively under low decline rates in low-permeability zones. Calculations based on production data reveal that, under ultra-low permeability conditions, Well V₁ exhibits a narrower and more elongated pressure drop funnel than Well V₂, which operates in a low permeability zone. Furthermore, well interference has a lesser effect on the expansion of the pressure drop funnel under ultra-low permeability conditions. These differences in the steady-state morphology of the pressure drop funnel ultimately lead to variations in production capacity. These findings provide a theoretical foundation and practical guidance for the rational development of low-permeability CBM reservoirs. Full article

The development of nanofluid-assisted heavy oil extraction can address critical challenges in global energy sustainability, particularly for ultra-heavy oil reserves characterized by high viscosity and low permeability. This study investigates the dual role of hydrophobic nanofluids in enhancing reservoir permeability and heat transfer efficiency. Through advanced triaxial shear seepage experiments and heat transfer experiments, the permeability and thermal conductivity of oil sands cores treated with hydrophobic silica-based nanofluids (0–0.15 wt%) were quantitatively analyzed. The results showed that the permeability increased by up to 536.59% (from 33.18 mD to 211.22 mD) after nanofluid treatment, which was attributed to nanoparticle-induced pore throat modification and reduced interfacial tension. At the same time, the thermal conductivity has increased by up to 132% (from 0.25 W/m·K to 0.58 W/m·K), significantly improving the heat transfer efficiency. There is a linear relationship between the concentration of nanofluids and the thermal conductivity, and the relationship between the thermal conductivity, and the strain of oil sands is established. This work provides a scientifically grounded framework for scaling nanofluid applications in field trials, offering a transformative pathway to reduce energy intensity and improve recovery rates in ultra-heavy oil exploitation. Full article