Search Results (32)

Gel treatments have been widely applied to control water production in oil and gas reservoirs. However, for water shutoff in dense gas reservoirs, most gel-based treatments focus on individual wells rather than the entire reservoir, exhibiting limited treatment depth, poor durability, and inadequate repeatability Notably, formation damage is a primary consideration in treatment design—most dense gas reservoirs have a permeability of less than 1 mD, making them highly susceptible to damage by formation water, let alone viscous polymer gels. Constrained by well completion methods, gelant can only be bullheaded into deep gas wells in most scenarios. Due to the poor gas/water selective plugging capability of conventional gels, the injected gelant tends to enter both gas and water zones, simultaneously plugging fluid flow in both. Although several techniques have been developed to re-establish gas flow paths post-treatment, treating gas-producing zones remains risky when no effective barrier exists between water and gas strata. Additionally, most water/gas selective plugging materials lack sufficient thermal stability under high-temperature and high-salinity (HTHS) gas reservoir conditions, and their injectivity and field feasibility still require further optimization. To address these challenges, treatment design should be optimized using non-selective gel materials, shifting the focus from directly preventing formation water invasion into individual wells to mitigating or slowing water invasion across the entire gas reservoir. This approach can be achieved by placing large-volume gels along major water flow paths via fully watered-out wells located at structurally lower positions. Furthermore, the drainage capacity of these wells can be preserved by displacing the gel slug to the far-wellbore region, thereby dissipating water-driven energy. This study evaluates the viability of placing gels in fully watered-out wells at structurally lower positions in an edge-water drive gas reservoir to slow water invasion into structurally higher production wells interconnected via numerous microfractures and high-permeability streaks. The gel system primarily comprises polyethyleneimine (PEI), a terpolymer, and nanofibers. Key properties of the gel system are as follows: Static gelation time: 6 h; Elastic modulus of fully crosslinked gel: 8.6 Pa; Thermal stability: Stable in formation water at 130 °C for over 3 months; Injectivity: Easily placed in a 219 mD rock matrix with an injection pressure gradient of 0.8 MPa/m at an injection rate of 1 mL/min; and Plugging performance: Excellent sealing effect on microfractures, with a water breakthrough pressure gradient of 2.25 MPa/m in 0.1 mm fractures. During field implementation, cyclic gelant injections combined with over-displacement techniques were employed to push the gel slug deep into the reservoir while maintaining well drainage capacity. The total volumes of injected fluid and gelant were 2865 m³ and 1400 m³, respectively. Production data and tracer test results from adjacent wells confirmed that the water invasion rate was successfully reduced from 59 m/d to 35 m/d. The pilot test results validate that placing gels in fully watered-out wells at structurally lower positions is a viable strategy to protect the production of gas wells at structurally higher positions. Full article

This study investigates the mechanisms behind strong water sensitivity in some low-clay-mineral-content tight conglomerate reservoirs in China’s Mahu Sag. Using core-scale water sensitivity tests, mineral analysis, in situ micro-CT scanning, and digital core techniques, we analyzed how water sensitivity alters pore structures across cores of varying permeability. Key findings include the following: (1) Water sensitivity damage increases as initial gas permeability decreases. (2) Despite low clay content, significant water sensitivity arises from the combined effect of water and velocity sensitivity, driven mainly by illite and kaolinite concentrated in gravel-edge fractures and key flow channels. (3) Water sensitivity causes non-uniform pore structure changes—some macropores and throats enlarge locally, reflecting heterogeneity. (4) Structural responses differ by permeability: medium–low permeability cores suffer from clay mineral swelling and particle migration, whereas high-permeability cores resist overall damage and may even have main flow paths enhanced by flushing. (5) Water sensitivity mainly degrades smaller pores but can improve larger ones, with the critical pore-size threshold between macro- and micro-pores inversely related to permeability. This work clarifies the pore-scale mechanisms of water sensitivity in some low-clay-mineral-content tight conglomerates, and can provide guidance for the optimization of water types injected into similar conglomerate reservoirs. Full article

In the global energy sector, water-bearing reservoir-typed gas storage accounts for about 30% of underground gas storage (UGS) reservoirs and is vital for natural gas storage, balancing gas consumption, and ensuring energy supply stability. However, when constructing the UGS in the M gas reservoir, selecting suitable areas poses a challenge due to the complicated gas–water distribution in the multi-layered water-bearing gas reservoir with a long production history. To address this issue and enhance energy storage efficiency, this study presents an integrated geomechanical-hydraulic assessment framework for choosing optimal UGS construction horizons in multi-layered water-bearing gas reservoirs. The horizons and sub-layers of the gas reservoir have been quantitatively assessed to filter out the favorable areas, considering both aspects of geological characteristics and production dynamics. Geologically, caprock-sealing capacity was assessed via rock properties, Shale Gouge Ratio (SGR), and transect breakthrough pressure. Dynamically, water invasion characteristics and the water–gas distribution pattern were analyzed. Based on both geological and dynamic assessment results, the favorable layers for UGS construction were selected. Then, a compositional numerical model was established to digitally simulate and validate the feasibility of constructing and operating the M UGS in the target layers. The results indicated the following: (1) The selected area has an SGR greater than 50%, and the caprock has a continuous lateral distribution with a thickness range from 53 to 78 m and a permeability of less than 0.05 mD. Within the operational pressure ranging from 8 MPa to 12.8 MPa, the mechanical properties of the caprock shale had no obvious changes after 1000 fatigue cycles, which demonstrated the good sealing capacity of the caprock. (2) The main water-producing formations were identified, and the sub-layers with inactive edge water and low levels of water intrusion were selected. After the comprehensive analysis, the I-2 and I-6 sub-layer in the M 8 block and M 14 block were selected as the target layers. The numerical simulation results indicated an effective working gas volume of 263 million cubic meters, demonstrating the significant potential of these layers for UGS construction and their positive impact on energy storage capacity and supply stability. Full article

The mechanism of low- to middle-rank coal seam gas accumulation in the Baode block on the eastern edge of the Ordos Basin is well understood. However, exploration efforts in the Shizuishan area on the western edge started later, and the current understanding of enrichment and accumulation rules is unclear. It is important to systematically study enrichment and accumulation, which guide the precise exploration and development of coal seam gas resources in the western wing of the basin. The coal seam collected from the Shizuishan area of Ningxia was taken as the target. Based on drilling, logging, seismic, and CBM (coalbed methane) test data, geological conditions were studied, and factors and reservoir formation modes of CBM enrichment were summarized. The results are as follows. The principal coal-bearing seams in the study area are coal seams No. 2 and No. 3 of the Shanxi Formation and No. 5 and No. 6 of the Taiyuan Formation, with thicknesses exceeding 10 m in the southwest and generally stable thickness across the region, providing favorable conditions for CBM enrichment. Spatial variations in burial depth show stability in the east and south, but notable fluctuations are observed near fault F1 in the west and north. These burial depth patterns are closely linked to coal rank, which increases with depth. Although the southeastern region exhibits a lower coal rank than the northwest, its variation is minimal, reflecting a more uniform thermal evolution. Lithologically, the roof of coal seam No. 6 is mainly composed of dense sandstone in the central and southern areas, indicating a strong sealing capacity conducive to gas preservation. This study employs a system that fuses multi-source geological data for analysis, integrating multi-dimensional data such as drilling, logging, seismic, and CBM testing data. It systematically reveals the gas control mechanism of “tectonic–sedimentary–fluid” trinity coupling in low-gentle slope structural belts, providing a new research paradigm for coalbed methane exploration in complex structural areas. It creatively proposes a three-type CBM accumulation model that includes the following: ① a steep flank tectonic fault escape type (tectonics-dominated); ② an axial tectonic hydrodynamic sealing type (water–tectonics composite); and ③ a gentle flank lithology–hydrodynamic sealing type (lithology–water synergy). This classification system breaks through the traditional binary framework, systematically explaining the spatiotemporal matching relationships of the accumulated elements in different structural positions and establishing quantitative criteria for target area selection. It systematically reveals the key controlling roles of low-gentle slope structural belts and slope belts in coalbed methane enrichment, innovatively proposing a new gentle slope accumulation model defined as “slope control storage, low-structure gas reservoir”. These integrated results highlight the mutual control of structural, thermal, and lithological factors on CBM enrichment and provide critical guidance for future exploration in the Ningxia Autonomous Region. Full article

The development of geo-energy resources, including oil, gas, and geothermal reservoirs, is being transformed through the creation of low-energy processes and innovative technologies. This Special Issue compiles cutting-edge research aimed at enhancing efficiency, sustainability, and recovery during geo-energy extraction. The published studies explore a diverse range of methodologies, such as the nanofluidic analysis of shale oil phase transitions, deep electrical resistivity tomography for geothermal exploration, and hybrid AI-driven production prediction models. Their key themes include hydraulic fracturing optimization, CO₂ injection dynamics, geothermal reservoir simulation, and competitive gas–water adsorption in ultra-deep reservoirs, and these studies combine advanced numerical modeling, experimental techniques, and field applications to address challenges in unconventional reservoirs, geothermal energy exploitation, and enhanced oil recovery. By bridging theoretical insights with practical engineering solutions, this Special Issue provides a comprehensive foundation for future innovations in low-energy geo-energy development. Full article

The thermal development in heavy oil reservoirs with edge and bottom water is poor, while gas huff-n-puff development shows a high recovery and strong adaptability. The formation of foamy oil during gas huff-n-puff is one of the reasons for the high recovery. In order to determine the factors affecting the foamy oil flow during gas huff-n-puff, experiments using a one-dimensional sandpack were conducted. The influences of drawdown pressure and cycle number were analyzed. The formation conditions of foamy oil were preliminarily clarified, and the enhanced oil recovery (EOR) mechanism of foamy oil was revealed. The experimental results show that the drawdown pressure and cycle number are two important factors affecting the formation of foamy oil. Foamy oil flow is prone to forming under a moderate drawdown pressure of 0.5–0.75 MPa, and being too small or too large is unfavorable. Foamy oil is more likely to form in the first two cycles, and it becomes increasingly challenging with the increase in the cycle number. These two factors reflect two necessary conditions for the formation of foamy oil during gas huff-n-puff: one is allowing the oil and gas to flow adequately to provide the shear and mixing for the generation of micro-bubbles, and the other is that the oil content should not be too small to avoid the inability to disperse and stabilize bubbles. The formation of foamy oil, on the one hand, increases the volume of the oil phase, and on the other hand, it reduces the mobility of the gas phase and slows down the pressure decline rate in the core, thereby enhancing the driving force for oil displacement. So, under the influence of the foamy oil, the gas production volume in a cycle declined by about 26%, and the average oil recovery increased by 4.5–6.9%. 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 fourth member of the Triassic in the Tahe Oilfield, as one of the key strata for clastic rock reservoirs, poses significant challenges to oil and gas exploration due to unclear identification of its depositional environments and sedimentary microfacies. Based on the guidance of sequence stratigraphy and sedimentological theories, this study comprehensively analyzed well logging data from more than 130 wells, core analysis from 9 coring wells (including lithology, sedimentary structures, and facies sequence characteristics), 3D seismic data (covering an area of 360 km²), and regional geological background. Combined with screening and settling method granularity experiments, the sedimentary characteristics of the sand body in the fourth member were systematically characterized. The results indicate the following: (1) In the Tahe Oilfield, the strata within the fourth member of the Triassic are predominantly characterized by marginal lacustrine subfacies deposits, with delta-front subfacies deposits developing in localized areas. (2) From the planar distribution perspective, influenced by the northwestern provenance, a small deltaic depositional system developed in the early stage of the fourth member in the northwestern part of the Triassic Akekule Formation. This system was dominated by subaqueous distributary channel sand bodies, which were subjected to erosion and reshaping by lake water, leading to the formation of several stable sand bars along the lake shoreline. In the later stage of the fourth member, as the lake level continued to recede, the area of deltaic deposition expanded westward, and deltaic deposits also developed in the central to slightly eastern parts of the study area. Based on this, a depositional model for the fourth member of the Triassic in the Tahe Oilfield has been established. (3) In the Tahe Oilfield, the sand bodies within the fourth member of the Triassic system gradually pinch out into mudstone, forming lithological pinch-out traps. Among these, the channel sand bodies and long belt sand ridges, due to their good sorting and high permeability, become favorable reservoirs for oil and gas accumulation. This study clarifies the sedimentary model of the fourth member and reveals the spatial differentiation mechanism of sand bodies under the control of lake-level fluctuations and ancient structures. It can provide exploration guidance for delta lake sedimentary systems similar to the edge of foreland basins, especially for efficient development of complex lithological oil and gas reservoirs controlled by multistage lake invasion–lake retreat cycles. Full article

The intricate gas–water distribution patterns in tight sandstone gas reservoirs significantly impede effective exploration and development, particularly challenging sweet spot prediction. In the Upper Paleozoic Shanxi Formation of the Ordos Basin, the complex and variable gas–water distribution characteristics remain poorly understood regarding their spatial patterns and controlling mechanisms. This study employs an integrated analytical approach combining casting thin sections, conventional porosity–permeability measurements, and mercury intrusion porosimetry to systematically investigate the petrological characteristics, pore structure, and physical properties of the Shan 2 member reservoirs in southern Yulin. Through the comprehensive analysis of production data coupled with structural and sand body distribution patterns, we identify three predominant formation water types: edge/bottom water, isolated lens-shaped water bodies, and residual water in tight sandstone gas layers. Our findings reveal that three primary factors govern water distribution in the Shan 2 member reservoirs: sand body architecture controlling fluid migration pathways; reservoir quality determining fluid storage capacity; and structural configuration influencing fluid accumulation patterns. This multi-scale characterization provides critical insights for optimizing development strategies in similar tight sandstone reservoirs. Full article

The natural gas industry has developed rapidly in recent years, with gas storage playing an important role in regulating winter and summer gas consumption and ensuring energy security. The Ke7010 sand body is a typical edge water condensate gas reservoir with an oil ring, and the construction of gas storage has been started. In order to clarify the feasibility of synergistic storage building for gas injection and production, the fluid characteristics during the synergistic reservoir building process were investigated through several rounds of drive-by experiments. The results show that the oil-phase flow capacity is improved by increasing the number of oil–water interdrives, and the injection and recovery capacity is improved by increasing the number of oil–gas interdrives; the reservoir capacities of the high-permeability and low-permeability rock samples increase by about 4.84% and 7.26%, respectively, after multiple rounds of driving. Meanwhile, a numerical model of the study area was established to simulate the synergistic storage construction scheme of gas injection and extraction, and the reservoir capacity was increased by 7.02% at the end of the simulation period, which was in line with the experimental results. This study may provide a reference for gas storage construction in the study area. Full article

The geological storage of carbon dioxide (CO₂) is a crucial technology for mitigating global temperature rise. Near-depleted edge–bottom water reservoirs are attractive targets for CO₂ storage, as they can not only enhance oil recovery (EOR) but also provide important potential candidates for geological storage. This study investigated CO₂-enhanced oil recovery and storage for a typical near-depleted edge–bottom water reservoir that had been developed for a long time with a recovery factor of 51.93%. To improve the oil recovery and CO₂ storage, new production scenarios were explored. At the near-depleted stage, by comparing the four different scenarios of water injection, gas injection, water-alternating-gas injection, and bi-directional injection, the highest additional recovery of 3.62% was achieved via the bi-directional injection scenario. Increasing the injection pressure led to a higher gas–oil ratio and liquid production rate. After shifting from the near-depleted to the depleted stage, the most effective approach to improving CO₂ storage capacity was to increase reservoir pressure. At 1.4 times the initial reservoir pressure, the maximum storage capacity was 6.52 × 10⁸ m³. However, excessive pressure boosting posed potential storage and leakage risks. Therefore, lower injection rates and longer intermittent injections were expected to achieve a larger amount of long-term CO₂ storage. Through the numerical simulation study, a gas injection rate of 80,000 m³/day and a schedule of 4–6 years injection with 1 year shut-in were shown to be effective for the case considered. During 31 years of CO₂ injection, the percentage of dissolved CO₂ increased from 5.46% to 6.23% during the near-depleted period, and to 7.76% during the depleted period. This study acts as a guide for the CO₂ geological storage of typical near-depleted edge–bottom water reservoirs. Full article

In-depth understanding of the gas–water seepage law caused by different degrees of gas layer perforation and varying gas production rates is key to determining a reasonable development technology policy for vertical heterogeneous edge-water gas reservoirs. Based on core physical data from the entire section of the X2 well, a large-scale high-pressure positive-rhythm profile model that takes into account the influence of “discontinuous interlayer” was innovatively established. The water intrusion process of the gas layer profile under different gas production rates and degrees of gas layer perforation was simulated using an electrical resistivity scanning device. The experimental model has an area of 3000 cm², with a maximum pressure of 70 MPa and a maximum temperature resistance of 150 °C. It includes 456 evenly distributed fluid saturation test points to accurately monitor the gas–water distribution, addressing the issues of small bearing pressure and insufficient saturation monitoring points found in other large-scale models. The experimental results show that, in heterogeneous reservoirs, the high-permeability zone controls the invasion path of edge water, which is the main reason for the uneven invasion of edge water. For the positive-rhythm profile of the F layer, a higher gas production rate (1000 mL/min) shortens the water-free gas recovery period of the gas well and reduces the recovery rate. Perforating the upper two-thirds of the layer can inhibit edge-water breakthrough, prolong the water-free gas recovery period of the gas well, enable the gas–water interface to advance more uniformly, and enhance the recovery degree. The results of this study greatly enhance our understanding of the water invasion characteristics of positive-rhythm reservoirs under the influence of different gas production rates and varying degrees of gas layer perforation. Full article

In order to clarify the water invasion law and residual gas distribution characteristics in edge and bottom water gas reservoirs with multi-well development, a large-scale three-dimensional physical simulation model was developed and a physical simulation experiment method for the water invasion law of multi-well development in sandstone gas reservoirs with strong water drives was established. Water invasion physical simulation experiments of multi-well development under the conditions of different water body multiples and production systems were conducted. The results show the following: (1) Gas wells near fractures and high-permeability zones experience the earliest water breakthrough. The larger the water body multiple, the faster the rate of water invasion, the earlier the water breakthrough time of gas wells, the more severe the degree of water invasion in gas reservoirs, and the lower the ultimate recovery rate. (2) Shutting in low-position gas wells immediately after water breakthrough reduces the overall water production of the gas reservoir and extends the overall water-free gas production period. However, the ultimate recovery rate is lower than when the wells are not shut in. (3) The residual gas in the fracture model is mainly distributed around the fracture and the edge of the gas reservoir, with the ultimate recovery rate ranging from 38.5% to 58.2%. The residual gas in the fracture–high-permeability zone model is mainly distributed around the fracture–high-permeability zone and the edge of the gas reservoir, with the ultimate recovery rate ranging from 28.32% to 41.8%. The experimental results have important guiding significance for the economical and efficient development of similar gas reservoirs. Full article

The West Lake Sag is abundant in oil and gas reserves, primarily in the Huagang Formation reservoir which serves as the primary source of production. The level of exploration is rather high, but there are still some unresolved issues, such as an unclear understanding of pore evolution features and reservoir growth mode. To tackle the aforementioned problems, this study employs optical microscopic examination, scanning electron microscope analysis, inclusion analysis, isotope analysis, X-ray diffraction analysis, and other techniques to elucidate the primary factors governing reservoir development and establish an analytical model regarding the cause of the sandstone reservoir. The results are as follows: (1) The sandstone reservoirs of the Huagang Formation of the Yuquan (abbreviated to YQ) Structure are now in the mesomorphic A stage as a whole, and minerals such as 4-phase authigenic quartz, 2-phase illite, 2-phase chlorite, 1-phase kaolinite, 1-phase ammonite mixing layer and 2-phase carbonate were formed during the diagenesis. (2) Feldspar and carbonate solution pores make up the majority of the reservoir space. About 10% of the porosity is made up of carbonate solution pores, which are the most prevalent reservoir space. Carbonate solution pores are primarily made up of metasomatic carbonate solution pores and cemented carbonate solution pores. Feldspar solution pores come next, contributing roughly 6.2% of the porosity. At 1.8%, residual intergranular holes are the least common. (3) The four main processes listed below are responsible for the creation of pores in the sandstone of the Huagang creation. The early carbonate cements resist the destruction of mechanical compaction and effectively preserve intergranular volume. The high content of feldspar provided a material basis for later dissolution. Early chlorite surrounding the edges of particles reduced the damage of authigenic minerals to porosity. The faults and cracks formed by the later structural inversion connected to the acidic water in the atmosphere, causing the dissolution of carbonate minerals and feldspar in the sandstone of the Huagang Formation. (4) Carbonate dissolution + feldspar dissolution type, carbonate dissolution type, and feldspar dissolution type are the three main types of reservoir formation in the Huagang Formation; the first two types mainly develop in the Upper Huagang Formation, while the latter mainly develops in the lower part of the Huagang Formation. The research results are conducive to the establishment of a geological prediction model for high-quality reservoirs of different geneses in the Huagang Formation and promote the exploration process of deep-seated hydrocarbons in the West Lake Sag. Full article

More and more offshore heavy oil resources are discovered and exploited as the focus of the oil and gas industry shifts from land to sea. However, unlike onshore heavy oil reservoirs, offshore heavy oil reservoirs not only have active edge and bottom water but also have different exploitation methods. In this paper, a typical special heavy oil reservoir in China was analyzed in detail, based on geology–reservoir–engineering integration technology. Firstly, it is identified as a self-sealing bottom water heavy oil reservoir by analyzing its geological characteristics and hydrocarbon accumulation mechanism. Secondly, the water cut is initially controlled by oil viscosity, but subsequently, by reservoir thickness through the analysis of oil and water production data. Thirdly, the bottom oil–water contact of the reservoir was re-corrected to build an accurate 3D geological model, based on the production history matching of a single well and the whole reservoir. Lastly, a scheme of thermal production coupled with cold production was proposed to exploit this special reservoir, and the parameters of steam, N₂, and CO₂ injection and production were optimized to predict oil production. This work can provide a valuable development model for the efficient exploitation of similar offshore special heavy oil reservoirs. Full article