Search Results (114)

Underground gas storage (UGS) in heterogeneous carbonate reservoirs is crucial for energy security but frequently faces wellbore instability challenges, which traditional static methods struggle to address due to dynamic full life cycle changes. This study systematically analyzes the dynamic evolution of wellbore stress in the Bs8 well (Qianmiqiao carbonate UGS) during drilling, acidizing, and injection-production operations, establishing a quantitative risk assessment model based on the Mohr–Coulomb criterion. Results indicate a significantly higher wellbore instability risk during drilling and initial gas injection stages, primarily manifested as shear failure, with greater severity observed in deeper well sections (e.g., 4277 m) due to higher in situ stresses. During acidizing, while the wellbore acid column pressure can reduce principal stress differences, the process also significantly weakens rock strength (e.g., by approximately 30%), inherently increasing the risk of wellbore instability, though the primary collapse mode remains shallow shear breakout. In the injection-production phase, increasing formation pressure is identified as the dominant factor, shifting the collapse mode from initial shallow shear failure to predominant wide shear collapse, notably at 90°/270° from the maximum horizontal stress direction, thereby significantly expanding the unstable zone. This dynamic assessment method provides crucial theoretical support for full life cycle integrity management and optimizing safe operation strategies for carbonate gas storage wells. Full article

The Carboniferous–Permian tight sandstone gas reservoirs in the Shenfu area of the Ordos Basin in China are characterized by the widespread development of multiple formations. However, significant differences exist among the tight sandstones of different formations, and their formation mechanisms and key controlling factors remain unclear, hindering the effective selection and development of favorable tight gas intervals in the study area. Through comprehensive analysis of casting thin section (CTS), scanning electron microscopy (SEM), cathodoluminescence (CL), X-ray diffraction (XRD), particle size and sorting, porosity and permeability data from Upper Paleozoic tight sandstone samples, combined with insights into depositional environments, burial history, and chemical reaction processes, this study clarifies the characteristics of tight sandstone reservoirs, reveals the key controlling factors of reservoir quality, confirms the differential evolutionary mechanisms of tight sandstone of different formations, reconstructs the diagenetic sequence, and constructs an evolution model of reservoir minerals and porosity. The research results indicate depositional processes laid the foundation for the original reservoir properties. Sandstones deposited in tidal flat and deltaic environments exhibit superior initial reservoir qualities. Compaction is a critical factor leading to the decline in reservoir quality across all formations. However, rigid particles such as quartz can partially mitigate the pore reduction caused by compaction. Early diagenetic carbonate cementation reduces reservoir quality by occupying primary pores and hindering the generation of secondary porosity induced by acidic fluids, while later-formed carbonate further densifies the sandstone by filling secondary intragranular pores. Clay mineral cements diminish reservoir porosity and permeability by filling intergranular and intragranular pores. The Shanxi and Taiyuan Formations display relatively poorer reservoir quality due to intense illitization. Overall, the reservoir quality of Benxi Formation is the best, followed by Xiashihezi Formation, with the Taiyuan and Shanxi Formations exhibiting comparatively lower qualities. Full article

Acid gas injection (AGI), which primarily involves injecting hydrogen sulfide (H₂S) and carbon dioxide (CO₂), is recognized as a cost-efficient and environmentally sustainable method for controlling sour gas emissions in oil and gas operations. This review examines case studies of twelve AGI projects conducted in Canada, Oman, and Kazakhstan, focusing on reservoir selection, leakage potential assessment, and geological suitability evaluation. Globally, several million tonnes of acid gases have already been sequestered, with Canada being a key contributor. The study provides a critical analysis of geochemical modeling data, monitoring activities, and injection performance to assess long-term gas containment potential. It also explores AGI’s role in Enhanced Oil Recovery (EOR), noting that oil production can increase by up to 20% in carbonate rock formations. By integrating technical and regulatory insights, this review offers valuable guidance for implementing AGI in geologically similar regions worldwide. The findings presented here support global efforts to reduce CO₂ emissions, and provide practical direction for scaling-up acid gas storage in deep subsurface environments. Full article

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

Aiming at the problems of insufficient natural productivity and large seepage resistance in low-permeability oil and gas reservoirs, a nano relative permeability improver based on nano SiO₂ was developed in this study. The nano relative permeability improver was prepared by the reversed-phase microemulsion method, and the formula was optimized (nano SiO₂ 5.1%, Span-80 33%, isobutanol 18%, NaCl 2%), so that the minimum median particle size was 4.2 nm, with good injectivity and stability. Performance studies showed that the improvement agent had low surface tension (30–35 mN/m) and interfacial tension (3–8 mN/m) as well as significantly reduced the rock wetting angle (50–84°) and enhanced wettability. In addition, it had good temperature resistance, shear resistance, and acid-alkali resistance, making it suitable for complex environments in low-permeability reservoirs. Full article

Lost circulation during drilling has significantly hindered the safe and efficient development of oil and gas resources. Supramolecular polymer gel–based lost circulation materials have shown significant potential for application due to their unique molecular structures and superior performance. Herein, a high–performance supramolecular polymer gel was developed, and the influence of reservoir conditions on the performance of the supramolecular polymer gel was investigated in detail. The results identified an optimal formulation for the preparation of supramolecular polymer gel comprising 15 wt% acrylamide, 3 wt% 2-acrylamide-2-methylpropanesulfonic acid, 2.6 wt% divinylbenzene, 5 wt% polyvinyl alcohol, 0.30 wt% cellulose nanofibers, and 3 wt% laponite. The performance of the gel-forming suspension and the resulting supramolecular polymer gel was influenced by various factors, including temperature, density, pH, and the intrusion of drilling fluid, saltwater, and crude oil. Nevertheless, the supramolecular polymer gels consistently exhibited high strength under diverse environmental conditions, as confirmed by rheological measurements. Moreover, the gels exhibited strong plugging performance across various fracture widths and in permeable formations, with maximum breakthrough pressures exceeding 6 MPa. These findings establish a theoretical foundation and practical approach for the field application of supramolecular polymer gels in complex geological formations, demonstrating their effectiveness in controlling lost circulation under challenging downhole conditions. Full article

In recent years, significant exploration successes and research progress in volcanic hydrocarbon reservoirs across China’s offshore basins have highlighted their importance as key targets for deep hydrocarbon exploration. In the Shimentan Formation of the Xihu Sag, East China Sea Shelf Basin (ECSSB), low-yield gas flows have been encountered through exploratory drilling; however, no major reservoir breakthroughs have yet been achieved. Assessing the large-scale reservoir potential of volcanic sequences in the Shimentan Formation is thus critical for guiding future exploration strategies. Based on previous exploration studies of volcanic reservoirs in other Chinese basins, this study systematically evaluates the hydrocarbon potential of these volcanic units by microscopic thin section identification, major element analysis, integrates drilling data with seismic interpretation techniques—such as coherence cube slicing for identifying volcanic conduits, dip angle analysis for classifying volcanic edifices, and waveform classification for delineating volcanic lithofacies. The main findings are as follows: (1) The Shimentan Formation is primarily composed of intermediate to acidic pyroclastic rocks and lava flows. Volcanic facies are divided into three facies, four subfacies, and six microfacies. Volcanic edifices are categorized into four types: stratified, pseudostratified, pseudostratified-massive, and massive. (2) Extensive pseudostratified volcanic edifices are developed in the Hangzhou Slope Zone, where simple and compound lava flows of effusive facies are widely distributed. (3) Comparative analysis with prolific volcanic reservoirs in the Songliao and Bohai Bay basins indicates that productive reservoirs are typically associated with simple or compound lava flows within pseudostratified edifices. Furthermore, widespread Late Cretaceous rhyolites in adjacent areas of the study region suggest promising potential for rhyolitic reservoir development in the Hangzhou Slope Zone. These results provide a robust geological foundation for Mesozoic volcanic reservoir exploration in the Xihu Sag and offer a methodological framework for evaluating reservoir potential in underexplored volcanic regions. Full article

In oil and gas production, reservoir heterogeneity causes plugging removal fluids to preferentially enter high-permeability zones, hindering effective production enhancement in low-permeability reservoirs. Traditional chemical diverting agents exhibit insufficient stability in high-temperature, high-salinity environments, risking secondary damage. To address these challenges, this study developed a water-sensitive self-thickening emulsion, targeting improved high-temperature stability, selective plugging, and easy flowback performance. Formulation optimization was achieved via orthogonal experiments and oil–water ratio adjustment, combined with particle size regulation and viscosity characterization. Core plugging experiments demonstrated the new emulsion system’s applicability and diverting effects. Results showed that under 150 °C and 15 × 10⁴ mg/L NaCl, the emulsion maintained a stable viscosity of above 302.7 mPa·s, with particle size D₅₀ increasing from 31.1 μm to 71.2 μm, exceeding API RP 13A’s 100 mPa·s threshold for acidizing diverters, providing an efficient plugging solution for high-temperature, high-salinity reservoirs. The injection pressure difference in high-permeability cores stabilized at 2.1 MPa, significantly enhancing waterflood sweep efficiency. The self-thickening mechanism, driven by salt-induced droplet coalescence, enables selective plugging in heterogeneous formations, as validated by core flooding tests showing a 40% higher pressure differential in high-permeability zones compared to conventional systems. Full article

During the early stages of drilling and completion in the Weiyuan shale gas wells, a large number of downhole materials were introduced, some of which inevitably remained in the wellbore or migrated into the reservoir. Over time, these residual materials underwent physicochemical reactions with reservoir minerals and fluids, gradually forming dense composite blockages that severely restricted the production efficiency of shale gas wells. The effectiveness of single-component unblocking agents in removing such blockages is limited. This study systematically analyzed the physicochemical properties of wellbore blockages in Weiyuan shale gas wells using refined chemical techniques. The results revealed that the main inorganic components of the blockages were Fe₃O₄ and SiO₂, while the organic components were primarily related to polymer materials from drilling and fracturing fluids. Based on the physicochemical characteristics of the blockages, a novel “organic dispersion and inorganic decomposition” unblocking strategy was proposed. Furthermore, an innovative approach that combined molecular simulation with laboratory experiments was employed to develop three unblocking fluid systems tailored to different blockage conditions: neutral, acidic, and composite. Performance evaluation showed that the composite unblocking fluid exhibited the best efficacy in treating these dense composite blockages, achieving a scale dissolution and dispersion efficiency of over 90%. Compared to the other two systems, the composite fluid demonstrated the longest penetration distance in simulated composite blockages, improving penetration by over 30%. In field applications, unblocking strategies were optimized based on whether the oil and casing were interconnected. For blocked wells without connectivity, a circulating wash method was used, while for interconnected wells, a dragging wash method was employed, ensuring efficient blockage removal. Full article

The Dolomite reservoir of the Maokou Formation is rich in gas resources in the central Sichuan Basin. Acid fracturing is an important technical means to improve reservoir permeability and productivity. The interaction mode of the dolomite and limestone acid system will affect the effect of reservoir reconstruction. In order to clarify the influence of complex structure on fracture morphology, we explore the fracturing effect of different acid systems. Physical simulation experiments of true triaxial acid fracturing were carried out with two acid systems and downhole full-diameter cores. The experimental results show: (1) After the carbonate rock is subjected to acid fracturing using a “self-generated acid + gel acid” system, the fracture pressure drops significantly by up to 60%. The morphology of the acid-eroded fractures becomes more complex, with an increase in geometric complexity of about 28% compared to a single acid solution system. It is prone to form three-dimensional “spoon” shaped fractures, and the surface of the acid-eroded fractures shows light yellow acid erosion marks. Analysis of the acid erosion marks indicates that the erosion depth on the fracture surface reaches 0.8–1.2 mm, which is deeper than the 0.2 mm erosion depth achieved with a single system. (2) Acid solution is difficult to penetrate randomly distributed calcite veins with a low porosity and permeability structure. When the fracture meets the calcite vein, the penetration rate of acid solution drops sharply to 15–20% of the initial value, resulting in a reduction of about 62% of the acid erosion area in the limestone section behind. And the acid erosion traces in the limestone behind the calcite vein are significantly reduced. The acid erosion cracks are easy to open on the weak surface between dolomite and limestone, causing the fracture to turn. (3) The results of field engineering and experiment are consistent, and injecting authigenic acid first in the process of reservoir reconstruction is helpful to remove pollution. The recovery rate of near-well permeability is more than 85% with pre-generated acid. Reinjection of gelled acid can effectively communicate the natural weak surface and increase the complexity of cracks. The average daily oil production of the completed well was increased from 7.8 m³ to 22.5 m³, and the increase factor reached 2.88. Full article

The characteristics of marine–continental transitional shale reservoirs and the performance parameters of fracturing fluids, such as pH and mineralization, play a crucial role in influencing the flowback efficiency of these fluids. Excessive retention of fracturing fluids within the reservoir can lead to a significant decrease in permeability, thereby diminishing gas well productivity. This study investigates shale samples sourced from the marine–continental transitional shale formation in the eastern Ordos Basin, along with field-collected fracturing fluid samples, including formation water, sub-formation water, distilled water, inorganic acids, and organic acids, through flowback experiments. The results show that: (1) the flowback rate of shale fracturing fluids exhibits a positive correlation with salinity, with low-salinity fluids showing a dual effect on clay mineral hydration. These fluids increase the pore volume of the sample from 0.003 cm³/g to 0.0037 cm³/g but also potentially reduce permeability by 31.15% to 99.96%; (2) the dissolution effects of inorganic and organic acids in the fracturing fluids enhance the flowback rate by 16.42% to 22.25%, owing to their chemical interactions with mineral constituents; (3) in the development of shale gas reservoirs, it is imperative to carefully devise reservoir protection strategies that balance the fracture-inducing effects of clay mineral hydration and expansion, while mitigating water sensitivity damage. The application of acid preflush, primarily including inorganic or organic acids, in conjunction with the advanced fracturing techniques, can enhance the connectivity of shale pores and fractures, thereby improving fracture conductivity, increasing the flowback rate of fracturing fluids, and ensuring sustained and high gas production from wells. 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

In response to the special requirements for shale gas reservoir stimulation, a novel environmentally responsive fracturing fluid thickener was designed and developed in this paper. N,N-dimethylhexadecylallylammonium chloride (C16DMAAC), N-vinylpyrrolidone (NVP), 2-acrylamido-2-methylpropanesulfonic acid (AMPS), and Acrylamide (AM) were used as functional monomers, and the synthesis of the target product was achieved successfully through free radical polymerization in an aqueous solution. The findings indicated that in the optimized situation, where the total monomer mass fraction was 25%, the ratio of AM:AMPS:C16DMAAC:NVP was 15:10:3:2, the initiator mass fraction was 0.3%, the pH was 6.5, and the temperature was 60 °C, the thickener achieved a number-average molecular weight of 1.13 × 10⁶. Furthermore, its remarkable thermal stability was manifested, as it only experienced a 15% mass loss in the temperature interval spanning from 40 °C to 260 °C. Performance evaluation results indicated that, at 120 °C, the viscosity of the thickener under study increased by over 49% compared to the control group. Simultaneously, in a 0.4 wt% CaCl₂ environment, it retained a high viscosity of 54.75 mPa·s. This value was 46.61 mPa·s greater than that of the control group. Furthermore, under the conditions of a temperature of 170 °C, the fracturing fluid viscosity remained above 68 mPa·s. Regarding the flow performance, within the flow rate range from 110 to 150 L/min, it showed a remarkable drag reduction effect, achieving a maximum drag reduction rate of 70%. At 150 °C, the fracturing fluid exhibited superior proppant-carrying efficacy, with a settlement rate that was 26.1% lower than that of the control group. The viscosity and residue content of the gel-broken fracturing fluid exceeded the requirements of industry standards. In particular, the residue content of this fracturing fluid was 21% lower than that of the control group. The research results provide an environmentally responsive fracturing fluid thickener with excellent performance for shale gas reservoir stimulation. Full article

This research makes a strong focus on improving fluid dynamics inside the reservoir after stimulation for enhancing oil and gas well performance, particularly in terms of increasing the Gas–oil ratio (GOR) and injectivity leading to a better productivity index (PI). Advanced stimulation operation using new formulated emulsified acid treatment greatly improves the reservoir permeability, allowing for better fluid movement and less formation damage. This, in turn, results in injectivity increases of at least 2.5 times and, in some situations, up to five times the original rate, which is critical for sustaining reservoir pressure and ensuring effective hydrocarbon recovery. The emulsified acid outperforms typical 15% HCl treatments in terms of dissolving and corrosion rates, as it is tuned for the reservoir’s pressure, temperature, permeability, and porosity. This dual-phase technology increases injectivity by five times while limiting the environmental and material consequences associated with spent and waste acid quantities. Field trials reveal significant improvements in injection pressure and a marked reduction in circulation pressure during stimulation, underscoring the treatment’s efficient penetration within the rock pores to enhance oil flow and sweep. This increase in performance is linked to the creation of the wormholing impact of the emulsified acid, resulting in improved fluid dynamics and optimized reservoir efficiency, as shown by the enhanced gas–oil ratio (GOR) in the four mentioned cases. A critical component of attaining such improvements is the capacity to effectively analyze and forecast reservoir behavior prior to executing the stimulation in real life. Engineers can accurately forecast injectivity gains and improve fluid injection tactics by constructing an advanced predictive model with low error margins, decreasing the need for time-consuming and costly trial-and-error approaches. Importantly, the research utilizes sophisticated neural network modeling to forecast stimulation results with minimal inaccuracies. This predictive ability not only diminishes the dependence on expensive and prolonged trial-and-error methods but also enables the proactive enhancement of treatment designs, thereby increasing efficiency and cost-effectiveness. This modeling approach based on several operational and reservoir factors, combines real-time field data, historical well performance records, and fluid flow simulations to verify that the expected results closely match the actual field outcomes. A well-calibrated prediction model not only reduces uncertainty but also improves decision making, allowing operators to create stimulation treatments based on unique reservoir features while minimizing unnecessary costs. Furthermore, enhancing fluid dynamics through precise modeling helps to improve GOR management by keeping gas output within appropriate limits while optimizing liquid hydrocarbon recovery. Finally, by employing data-driven modeling tools, oil and gas operators can considerably improve reservoir performance, streamline operational efficiency, and achieve long-term production growth through optimal resource usage. This paper highlights a new approach to optimizing reservoir productivity, aligning with global efforts to minimize environmental impacts in oil recovery processes. The use of real-time monitoring has boosted the study by enabling for exact measurement of post-injectivity performance and oil flow rates, hence proving the efficacy of these advanced stimulation approaches. The study offers unique insights into unconventional reservoir growth by combining numerical modeling, real-world data, and novel treatment methodologies. The aim is to investigate novel simulation methodology, advanced computational tools, and data-driven strategies for improving the predictability, reservoir performance, fluid behavior, and sustainability of heavy oil recovery operations. Full article

Hydraulic fracturing experimentation is an essential tool for understanding the application of hydraulic fracturing in producing hydrocarbons from unconventional reservoirs. Laboratory testing methods such as uniaxial, biaxial, and true triaxial testing have limited accuracy due to the simplified consideration of in situ stresses, geological conditions, and subsurface temperature variations. Despite these limitations, hydraulic fracturing experimentation provides valuable insights for the execution of hydraulic fracturing in field conditions. Key factors influencing the accuracy and generalization of experimental results include sample specifications, stress regime, saturation conditions, and fracturing fluid properties. However, extending laboratory-scale conclusions to the field scale requires appropriate scaling factors. This paper provides an overview of the main concepts in hydraulic fracture modeling, including design considerations, laboratory scaling, uniaxial, biaxial, and triaxial testing in hydraulic fracturing experimentation and major numerical simulation methodologies. Numerical methods, such as the discrete element method, discontinuous deformation analysis, rigid body spring network, and virtual internal bond, effectively simulate complex mechanisms like fracture initiation, propagation, fracture–fluid interactions, and the influence of rock microstructure, complementing the experimental findings. Advancements in these models, including the integration of nonlinear elasticity in virtual internal bonds and coupling with finite element analysis or fluid network models, continue to enhance the predictive accuracy and efficiency, particularly in complex geological settings, offering promising applications for optimizing shale gas production, acid fracturing, and geotechnical engineering. Furthermore, this review discusses the importance of in situ stresses, geological conditions, and temperature in both laboratory experiments and numerical simulations, highlighting future directions to consider in laboratory-scale analyses of hydraulic fracturing. Full article