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To solve the problems of high sampling requirements and low predictive accuracy resulting from the complexity, uniqueness, and randomness of predicting the risk of the CO2 and N2 injection to enhance coal seam gas drainage (CO2/N2–ECGD) technology. The principal component analysis (PCA) method to reduce the dimensionality of the factor data that contribute to the effect risk of the technology was adopted. And the particle swarm optimization (PSO) method was implemented to search for optimal hyperparameters in support vector machine (SVM) by particle search, as a solution to the traditional SVM hyperparameters optimization problem. A novel risk prediction model using machine learning algorithms for gas injection displacement technology was constructed. The prediction results were tested and compared with those of backpropagation (BP), Random Forest (RF), and Decision Tree (DT) models using data from 29 gas injection displacement field projects in China. The results demonstrated that the SVM model had greater accuracy in prediction than the other three models. Additionally, after PSO optimization and dimensionality reduction, the PCA–PSO–SVM model reached 100% prediction accuracy, while requiring less modeling and operation time. The study provided a reliable and reasonable model for predicting technical effects, along with a theoretical basis for risk management and prevention. First, the technology's influencing indicators were analyzed by examining its mechanisms. Second, we utilized the PCA method to reduce the dimensionality of the factor data that contribute to the risk of the technology's effects. Third, we implemented the PSO method to search for optimal hyperparameters in the SVM through particle search, as a solution to the traditional SVM hyperparameters optimization problem. Finally, the prediction results were tested and compared with those of BP, RF, and DT models using data from 29 gas injection displacement field projects in China. The SVM model was found to have greater accuracy in prediction than the other three models. After PSO optimization and dimensionality reduction, the PCA–PSO–SVM model achieved 100% prediction accuracy while requiring less modeling and operation time. The study presents a valid and reasonable model for predicting technical effects and a theoretical basis for risk management and prevention. [ABSTRACT FROM AUTHOR]

For the high temperature (130 °C), high pressure (30 MPa), and high salinity (2.5 × 105 mg/L) of formation water conditions in the target block of the Tarim Basin Oilfield in northwest China, dodecyl hydroxy sulfobetaine surfactant was evaluated for its foaming performance, thermal stability, adsorption performance. The evaluation results showed that the surfactant exhibited good foaming ability and thermal stability than the general carboxy betaine under the above harsh conditions. The static adsorption of the surfactant on the surface of quartz sand particles was less than 1 mg/g with a concentration of less than 0.4%, which met the requirement for foaming agent adsorption. Moreover, the results of core displacement experiments indicated that, when simultaneously injecting 0.4% foaming agent and gas at a volume ratio of 3:7 into the cores of 38 mD, 161.4 mD, and 478.7 mD, foam with low mobility of less than 2 mD/cP could be generated; in the 57.3 mD Berea core, the resistance factor of foam generated by 8 cycles of injecting gas-liquid alternately with gas-liquid volume ratio ranging from 0.2:0.1 to 0.4:0.1 was nearly 20, and the residual resistance factor was greater than 5 after 5 PV of continuous gas injection. The results of the study can guide the selection of foaming agents for gas mobility control in high-temperature and high-salinity sandstone reservoirs. [ABSTRACT FROM AUTHOR]

The long‐term cyclic gas injection and production mode of the gas storage will lead to accelerated deformation of the surrounding rock of the old cavity, and even the instability and failure of the cavity. Considering the geological conditions and cavity measurement data of the old cavity of the horizontal butted‐well in China, the deformation and failure characteristics of the long‐term cyclic injection‐production process of the surrounding rock of the old cavity under different internal pressure difference and injection‐production frequency are studied. The long‐term stability of the gas storage is predicted by six indexes: the deformation of surrounding rock, dilatancy safety factor, volume shrinkage rate, plastic zone volume, equivalent strain, and no tensile stress. The results show that with the increase of operation duration and cycle times, the deformation, volume shrinkage rate, and plastic zone volume of the surrounding rock gradually increase after the old cavity is reconstructed into the gas storage and the difference of results under different UGS and CAES gradually expands. The stability of the surrounding rock of the old cavity under the cycle action of CAES will be lower. The number of cycles has a limited impact on the stability of the surrounding rock of the old cavity, while the operation duration and injection‐production pressure are the main determinants of the stability of the surrounding rock of the old cavity. If the old cavity of the salt mine is reconstructed into CAES, the parameters such as the number of cycles, the operation duration, and the injection‐production pressure still need to be considered comprehensively. The research results can provide reference value for the reasonable design of the gas storage pressure range of the old cavity and the safety and stability evaluation of the surrounding rock. [ABSTRACT FROM AUTHOR]

Shale oil resources have enormous potential and broad development prospects in China. Especially with the rapid development of horizontal well volume fracturing technology, the production of shale oil has been greatly increased, and it has become an important position to increase oil and gas storage and production. However, due to the existence of artificial and natural fractures produced by fracturing, gas channeling will occur in the process of huff-n-puff gas injection, which will affect the production and lead to poor development effect. In this paper, foam is used as an anti-channeling agent in the process of huff-n-puff gas injection. The results of microfluidic experiments show that the production mode of foam in porous media is liquid membrane hysteresis and liquid membrane separation. In porous media, foam first blocks large channels such as fractures, and then enters the matrix. The oil recovery mechanism of foam assisted gas injection in porous media is to improve the sweep efficiency and oil displacement efficiency of gas. Compared with N2 huff-n-puff, the oil recovery of the first cycle of foam assisted N2 huff-n-puff increased by 4.50%, and the third cycle increased by 9.58%. It is proved that foam has good anti channeling effect in gas huff-n-puff injection process. The research results provide an effective method for efficient gas injection development of shale oil. [ABSTRACT FROM AUTHOR]

Depleted gas reservoirs type underground gas storage (depleted-UGS) are important facilities used to solve the imbalance of natural gas supply and demand. However, gas storage has high energy consumption, and depleted-UGS faults are widely distributed and divided into multiple disconnected blocks. Excessive pressure variation between reservoir blocks (RBs) will affect the stability of depleted-UGS operation. A multiobjective optimization model is established to solve the economic security scheduling problem of depleted-UGS. The model takes the pressure variation of RB and the energy consumption of the compressor as the optimization objectives, coupled with the constraints of reservoir seepage pressure drop and wellbore flow pressure drop. To find a high-performance algorithm to solve the depleted-UGS operation optimization problem, three multiobjective algorithms are tested, and reference vector guided evolutionary algorithm (RVEA) is chosen as the solution. We apply this model to a large depleted-UGS in China and use the RVEA to solve the optimal gas injection scheme for the depleted-UGS under two scenarios of low RB pressure variation and high RB pressure variation. The findings suggest that the optimized solution is more inclined to allocate more gas injection to the block with lower pressure and higher elastic yield. For the scenario where the pressure of the RBs is relatively balanced, the optimization scheme can reduce the energy consumption by 5.2% and the pressure difference by 79.3%. For scenarios with large pressure differences among RBs, the optimization scheme can reduce energy consumption by 17.4% and pressure difference by 41.3%. [ABSTRACT FROM AUTHOR]

The development of shale oil often encounters a series of challenges, such as insufficient natural energy, rapid declines in production, and low oil recovery. Given its wide availability and low cost, natural gas serves as an ideal injection medium to enhance shale oil recovery. Based on the foundational data from Chang 7 block X in the Ordos Basin and considering the influence of reservoir stress sensitivity, this study uses numerical simulation methods in conjunction with the random forest algorithm to examine gas flooding in shale oil. This research aims to identify the key factors influencing the effectiveness of natural gas flooding for shale oil and to establish a chart for the adaptive natural gas flooding development boundary. The findings suggest that, for reservoirs with permeability less than 0.2 × 10−3 μm2 and oil saturation below 55%, it is advisable to adopt longer fracture lengths during hydraulic fracturing to achieve better development results. After 10 years of gas flooding, continuing the use of this method is not recommended, and adjusting of the development strategy becomes essential. For extended development periods, avoiding long-length fractures is crucial to mitigate gas channeling and ensure the effectiveness of the development process. This study offers theoretical guidance and technical support for developing shale reservoirs with natural gas flooding. [ABSTRACT FROM AUTHOR]

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With the popularization of natural gas and the requirements for environmental protection, the development and utilization of natural gas is particularly important. The status of natural gas in China's oil and gas exploration and development is constantly improving, and the country is paying more and more attention to the exploitation and utilization of natural gas. The Upper Paleozoic tight sandstone in the Ordos Basin is characterized by low porosity, low permeability and a large area of concealed gas reservoirs. By injecting carbon dioxide into the formation, the recovery rate of natural gas can be improved, and carbon neutrality can be realized by carbon sequestration. Injecting greenhouse gases into gas reservoirs for storage and improving recovery has also become a hot research issue. In order to improve the recovery efficiency of tight sandstone gas reservoirs, this paper takes the complex tight sandstone of the Upper Paleozoic in the Ordos Basin as the research object; through indoor physical simulation experiments, carried out the influence of displacement rate, fracture dip angle, core permeability, core dryness and wetness on CO2 gas displacement efficiency and storage efficiency; and analyzed the influence of different factors on gas displacement efficiency and storage efficiency to improve the recovery and storage efficiency. The research results show that under different conditions, when the injection pore volume is less than 1 PV, the relationship between the CH4 recovery rate and the CO2 injection pore volume is linear, and the tilt angle is 45°. When the injection pore volume exceeds 1 PV, the CH4 recovery rate increases slightly with the increase in displacement speed, the recovery rate of CO2 displacement CH4 is between 87–97% and the CO2 breakthrough time is 0.7 PV–0.9 PV. In low-permeability and low-speed displacement cores, the diffusion of carbon dioxide molecules is more significant. The lower the displacement speed is, the earlier the breakthrough time is, and the final recovery of CH4 slightly decreases. Gravity has a great impact on carbon sequestration and enhanced recovery. The breakthrough of high injection and low recovery is earlier, and the recovery of CH4 is about 3.3% lower than that of low injection and high recovery. The bound water causes the displacement phase CO2 to be partially dissolved in the formation water, and the breakthrough lags about 0.1 PV. Ultimately, the CH4 recovery factor and CO2 storage rate are higher than those of dry-core displacement. The research results provide theoretical data support for CO2 injection to improve recovery and storage efficiency in complex tight sandstone gas reservoirs. [ABSTRACT FROM AUTHOR]

Copyright of Petroleum Geology & Recovery Efficiency is the property of Petroleum Geology & Recovery Efficiency and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Bottom-blowing copper smelting is a bath smelting technology recently developed in China. It has the advantages of good adaptability of raw materials, high oxygen utilization and thermal efficiency, and flexible production capacity. Plume eye is a unique phenomenon observed in the bottom-blowing copper-smelting furnace where the slag on the surface of the bath is pushed away by the high-pressure gas injected from the bottom. The existence of plume eye was first confirmed by analyzing the quenched industrial samples collected above the gas injection area and then investigated by laboratory water model experiments. Combining the plant operating data and the smelting mechanism of the copper concentrate, the role of the plume eye in bottom-blowing-enhanced smelting is analyzed. It reveals that the direct dissolution of copper concentrate as a low-grade matte into the molten matte can significantly accelerate the reactions between the concentrate and oxygen. The productivity of the bottom-blowing furnace is therefore increased as a result. The effects of the gas flow rate and thickness of the matte and of the slag layer on the diameter of the plume eye were studied using water-model experiments. It was found that increasing the gas flow and the thickness of the matte and reducing the thickness of the slag can increase the diameter of the plume eye. This work is of great significance for further understanding the copper bottom-blowing smelting technology and optimizing industrial operations. [ABSTRACT FROM AUTHOR]

Copyright of Clean Coal Technology is the property of Clean Coal Technology and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Thermal recovery technology is generally suitable for shallow lays due to the higher thermal loss for the deep heavy-oil reservoirs. Non-thermal recovery technologies, such as the non-condensate gas injection technology, are not limited by the reservoir depth and could be extensively applied for the heavy-oil reservoir. Many experimental studies and field applications of non-condensate gas injection have been conducted in heavy-oil reservoirs. The injected non-condensate gas could achieve dynamic miscibility with heavy oil through multiple contacts, which has a significant viscosity-reduction effect under the reservoir conditions. In addition, the equipment involved in the gas injection operation is simple. There are many kinds of non-condensate gases, and common types of gases include N2 and CO2 due to abundant gas sources and lower prices. Moreover, CO2 is a greenhouse gas and the injection of CO2 into the reservoir would have environmental benefits. The non-thermodynamic method is to inject N2 and CO2 separately to produce heavy oil based on the mechanism of the volume expansion of crude oil to form elastic flooding and reduce crude oil viscosity and foamy oil flow. Steam injection recovery of the thermodynamics method has the disadvantages of large wellbore heat loss and inter-well steam channeling. The addition of N2, CO2, and other non-condensate gases to the steam could greatly improve the thermophysical properties of the injected fluid, and lead to higher expansion performance. After being injected into the reservoir, the viscosity of heavy oil could be effectively reduced, the seepage characteristics of heavy oil would be improved, and the reservoir development effect could be improved. Non-condensate gas injection stimulation technology can not only effectively improve oil recovery, but also help to achieve carbon neutrality, which has a very broad application prospect in the future oil recovery, energy utilization, environmental improvement, and other aspects. [ABSTRACT FROM AUTHOR]

The injection of N2 into coal reservoir has great potential in improving recovery of coalbed methane (CBM). In this study, a numerical model was established based on the GEM component model to evaluate the influences of different N2 injection parameters (production injection well spacing, gas injection timing, gas injection duration, gas injection rate, and the bottom-hole injection pressure) on the production of CBM in the Shizhuang Block of Qinshui Basin, China. Based on the economic benefit of CBM production, the production increasing rate and nitrogen replacement ratio were established to optimize the N2 injection parameters. The results show that (1) the production injection well spacing had the greatest influence on CBM production, followed by injection duration and the bottom-hole injection pressure, and injection timing and injection rate had a relatively small influence. (2) With increasing gas injection duration, injection rate, and the bottom-hole injection pressure, the rate of production increased and the nitrogen replacement ratio decreased. (3) The optimal N2 injection scheme was revealed with the production injection well spacing of 180 m, the injection timing of a second year after gas production, an injection duration of 7 years, an injection rate of 5000 m3/d, and a bottom-hole injection pressure of 10 MPa. Under these conditions, the rate of production increasing rate, the nitrogen displacement ratio, and the regional recovery of the four production wells were 18.14%, 0.5, and 48.96%, respectively, some 8.88% higher than that without nitrogen displacement, showing good effect in terms of CBM production. [ABSTRACT FROM AUTHOR]

Copyright of Petroleum Geology & Recovery Efficiency is the property of Petroleum Geology & Recovery Efficiency and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

The national policy of peak carbon dioxide emission and carbon neutrality has pointed out the technological direction for the development of the petroleum industry in China. In order to efficiently utilize CO2 gas source to enhance oil recovery, n-butylamine is taken as the plugging channeling agent for experiment study to plug the produced channeling-path during the process of CO2 flooding in ultra-low permeability reservoir. The contents of the experiment included three parts: reaction mechanism of n-butylamine with CO2, evaluation of the injection performance of n-butylamine, and the extent of enhanced oil recovery after plugging the gas channeling by using n-butylamine. Reaction product of n-butylamine and CO2 is white solid, which is a type of organic urea so that it can be used to plug the gas channeling. N-butylamine has a good injection performance after adding protecting slug on the condition of high temperature. 80% of the whole volume of core can be spread after injecting 0.3 PV of n-butylamine. During plugging and displacement experiment of heterogeneous cores, oil recovery can be greatly enhanced by 25–30% after injecting n-butylamine. Experimental results show that it can provide a new train of thought for the gas injection development of fractured, heterogeneous and ultra-low permeability reservoirs by using n-butylamine to plug the high permeability area. [ABSTRACT FROM AUTHOR]

The lower Wuerhe formation reservoir of the 8th district is a blocky, ultra-low-permeability gravel reservoir with poor waterflooding development, and it is urgent to attack the gas injection gravity flooding. The barrier property of seepage barriers such as interlayers developed inside the reservoir is very important for the study of gas injection gravity flooding. The mineral composition, pore throat structure, and physical characteristics of the interlayer rocks were studied by X-ray diffraction (XRD) whole-rock analysis and nuclear magnetic resonance (NMR). The gas injection breakthrough pressure of the interlayer was studied by core breakthrough experiment and digital core simulation. Based on the determination of the interlayer criteria, logging was used to interpret and characterize the interlayer. The effects of different types of interlayer combinations on gas injection were studied by combining the physical model and numerical simulation methods. The results showed that the lithology of the interlayer in the lower Wuerhe formation of the 8th district was mainly mud-bearing fine gravel with microporosity, average porosity of 6.1% and permeability of 0.0043 mD. The interlayer gas injection breakthrough pressure and permeability were in a logarithmic linear relationship, and the lower limit of gas injection breakthrough under reservoir conditions was 0.003 mD. Initially, it is difficult to flood the upper remaining oil of the gas injection due to the blockage of the interlayer, while in the middle and late stage, the gas-liquid interface gradually reached stability with the increase in injected gas, which has little impact on the final recovery. These results indicate that it is feasible to carry out gas injection gravity flooding in this reservoir. [ABSTRACT FROM AUTHOR]

The largest carbonate condensate field has been found in the Tarim Basin, NW China. Different from sandstone condensate gas reservoirs, however, the conventional gas injection for pressure maintenance development is not favorable for Ordovician fracture-cave reservoirs. Based on this, in this paper, 21 sets of displacement experiments in full-diameter cores and a pilot test in 11 boreholes were carried out to study enhanced oil recovery (EOR) in complicated carbonate reservoirs. The experimental results show that the seepage channels of the gas condensate reservoirs are fractures, which are quite different from sandstone pore-throat structures. Condensate oil recovery using water injection was up to 57–88% in unfilled fractured caves and at ca. 52–80% in sand-filled fractured caves. These values are much higher than the 14–46% and 17–58% values obtained from the depletion and gas injection experiments, respectively. The water injection in 11 wells showed that the condensate oil recovery increased by 0–17.7% (avg. 3.1%). The effective EOR for residual oil replacement using water injection may be attributed to fractures, as the gas channel leads to an ineffective gas circulation and pipe flow in fracture-cave reservoirs, which is favorable for waterflood development. The complicated fracture network in the deep subsurface may be the key element in the varied and lower oil recovery rates obtained from the wells than from the experiments. This case study provides new insights for the exploitation of similar condensate gas reservoirs. [ABSTRACT FROM AUTHOR]

Gas flooding has proven to be a promising method of enhanced oil recovery (EOR) for mature water-flooding reservoirs. The determination of optimal well control parameters is an essential step for proper and economic development of underground hydrocarbon resources using gas injection. Generally, the optimization of well control parameters in gas flooding requires the use of compositional numerical simulation for forecasting the production dynamics, which is computationally expensive and time-consuming. This paper proposes the use of a deep long-short-term memory neural network (Deep-LSTM) as a proxy model for a compositional numerical simulator in order to accelerate the optimization speed. The Deep-LSTM model was integrated with the classical covariance matrix adaptive evolutionary (CMA-ES) algorithm to conduct well injection and production optimization in gas flooding. The proposed method was applied in the Baoshaceng reservoir of the Tarim oilfield, and shows comparable accuracy (with an error of less than 3%) but significantly improved efficiency (reduced computational duration of ~90%) against the conventional numerical simulation method. [ABSTRACT FROM AUTHOR]

The construction of underground gas storage mostly focuses on depleted gas reservoirs. However, the depleted gas reservoir used to build underground gas storage in China is located far from the main gas consumption economic zone. It is necessary to reconstruct underground gas storage using nearby reservoirs in order to meet the needs of economic development. The complex three-phase seepage characteristics encountered in the process of reconstruction of underground gas storage reservoirs seriously affect their storage and injection production capacities. Combined with the mechanism of multiphase seepage and the multicycle injection production mode during the process of gas storage construction, the feasibility of rebuilding gas storage in medium- and low-permeability reservoirs was evaluated through relative permeability experiments and core injection production experiments. The results showed that the mutual driving of two-phase oil–water systems will affect the storage space and seepage capacity, that the adverse effect will be weakened after multiple cycles, and that increasing the gas injection cycle can enhance the gas-phase seepage capacity and improve the crude oil recovery. Therefore, we found that it is feasible to reconstruct underground gas storage in medium- and low-permeability reservoirs, which lays a foundation for the development of underground gas storage in China. [ABSTRACT FROM AUTHOR]

Copyright of Clean Coal Technology is the property of Clean Coal Technology and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

A new scheme is proposed to improve the electron beam quality of ionization-induced injection by tailoring gas profile in laser wakefield acceleration. Two-dimensional particle-in-cell simulations show that the ionization-induced injection mainly occurs in high-density stage and automatically truncates in low-density stage due to the decrease of the wakefield potential difference. The beam loading can be compensated by the elongated beam resulting from the density transition stage. The beam quality can be improved by shorter injection distance and beam loading effect. A quasi-monoenergetic electron beam with a central energy of 258 MeV and an energy spread of 5.1% is obtained under certain laserâ€"plasma conditions. [ABSTRACT FROM AUTHOR]

High temperature nitrogen, injection into coal seams is supposed to improve the permeability and thus maintain the safety of underground mining. A novel triaxial apparatus is recently developed, aiming at providing the effective method to evaluate the effect of high temperature nitrogen injection. The main feature of this novel apparatus is its high confining pressure, gas injection with high pressure as well as the high temperature. This new device can be either used for natural coal samples (e.g. intact or fractured) or the synthetic coal samples. A series of leakage tests were conducted to verify the feasibility of this instrument, the results of which have confirmed that the maximum pressure (i.e. 10 MPa) can be reached. In addition, the high temperature and pressure of nitrogen gas can also be sustain at the requested level. Based on the preliminary tests on the instrument, a large amount of tests were carried out to evaluate the effect of nitrogen injection in enhancing the permeability of coking coal from the Pingdingshan coalfield, China, and the influence of high temperature nitrogen injection on mechanical parameters of coal was obtained. [ABSTRACT FROM AUTHOR]

Copyright of Journal of China University of Petroleum is the property of China University of Petroleum and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

N 2 injection to enhance coal seam gas drainage is an effective technology for coalbed methane recovery. Nevertheless, there is a limited body of research addressing the application of ECBM technology for gas management in low permeability coal seams within underground coal mines, and the effect is uncertain. Additionally, numerical simulators have been challenged to accurately predict methane emissions during gas injection and replacement. In this study, firstly, an underground field trials of N 2 injection replacement in a coal mine with low-permeability coal seams in China were conducted, and a comparative analysis of "N 2 injection to enhance gas drainage" and "conventional drainage" technique was performed. The result show that injecting pressurized N 2 into a low-permeability coal seam could increase the pressure gradient to promote the directional flow of free gas from the coal seam cracks to the gas-production boreholes. After N 2 injection, the mixed flow rate and CH4 flow rate significantly increased. Additionally, the gas content in the coal seam in the experimental area significantly decreased. Secondly, the lag-effect was discussed. Upon discontinuation of N 2 injection, the gas-producing mixed flow initially increased slightly, then gradually decreased, and eventually settled at a high level. Despite the attenuation of N 2 injection volume, the CH 4 flow rate continued to increase during intermittent injection and remained high after gas injection discontinuation. Finally, three deep learning algorithms (BP, LSTM, and TCN) were employed to predict the dynamic change of gas drainage in coal seams displaced by N 2 injection, based on the results of the field test. The results indicated that deep learning algorithms exhibited superior prediction performance. The TCN model demonstrated the lowest approximation error rate, displaying optimal performance in predicting the CH 4 flow rate during nitrogen injection for enhanced gas drainage. Additionally, it exhibited good applicability to other similar field test results. [Display omitted] • A field test of N 2 -ECBM in low-permeability coal seams was carried. • The gas production laws of "N 2 injection to enhance drainage" were analyzed. • The lag-effect during intermittent gas injection was analyzed. • 4.The deep learning algorithms was applied to "N 2 injection to enhance drainage". [ABSTRACT FROM AUTHOR]

In this work, a novel thermal–hydraulic–mechanical (THM) coupling model is developed, where the real geological parameters of the reservoir properties are embedded. Accordingly, nine schemes of CO2 injection well (IW) and CH4 production well (PW) are established, aiming to explore the behavior of free gases after CO2 is injected into the depleted Wufeng–Longmaxi shale. The results indicate the free CH4 or CO2 content in the shale fractures/matrix is invariably heterogeneous. The CO2 involvement facilitates the ratio of free CH4/CO2 in the matrix to that in the fractures declines and tends to be stable with time. Different combinations of IW–PWs induce a difference in the ratio of the free CH4 to the free CO2, in the ratio of the free CH4/CO2 in the matrix to that in the fractures, in the content of the recovered free CH4, and in the content of the trapped free CO2. Basically, when the IW locates at the bottom Wufeng–Longmaxi shale, a farther IW–PWs distance allows more CO2 in the free phase to be trapped; furthermore, no matter where the IW is, a shorter IW–PWs distance benefits by getting more CH4 in the free phase recovered from the depleted Wufeng–Longmaxi shale. Hopefully, this work is helpful in gaining knowledge about the shale-based CO2 injection technique. [ABSTRACT FROM AUTHOR]

To tackle the problem that wells that are deployed in a specific pattern based on the requirements of gas reservoir development are not suitable for gas storage, we have conducted concentrically circular injection and production simulation experiments for gas storage, discovered the existence of a threshold radius, denoted by Rt, and derived the expression for Rt. Based on the analysis and discussion results, we propose a strategy for deploying gas storage wells in specific patterns. The expression for Rt shows that it is affected by factors such as the gas storage gas production/injection time, the upper pressure limit, the lower pressure limit, the bottomhole flow pressure at the ends of injection and production, the and permeability. The analysis and discussion results show that the Rt of a gas storage facility is much smaller than the Rt for gas reservoir development. In the gas storage facilities in China, the Rt for gas production is less than the Rt for the gas injection, and Rt increases with the difference in the operating pressure and with permeability K. Based on the characteristics of Rt, we propose three suggestions for gas storage well pattern deployment: (1) calculate Rt according to the designed functions of the gas storage facility and deploy the well pattern according to Rt; (2) deploy sparser, large‐wellbore patterns in high‐permeability areas and denser, small‐wellbore patterns in high‐permeability areas; and (3) achieve the gas injection well pattern by new drilling, and the gas production well pattern through a combination of the gas injection well pattern and old wells. By assessing a gas storage facility with a perfect well pattern after a number of adjustments, we found that the Rt of the 12 wells calculated in this paper is basically close to the corresponding actual radius, which validates our method. The results of this study provide a methodological basis for well pattern deployment in new gas storage construction. [ABSTRACT FROM AUTHOR]

Gas injection processes are among the effective methods for enhanced oil recovery. Miscible and/or near miscible gas injection processes are among the most widely used enhanced oil recovery techniques. The successful design and implementation of a miscible gas injection project are dependent upon the accurate determination of minimum miscibility pressure (MMP), the pressure above which the displacement process becomes multiple-contact miscible. This paper presents a method to get the characteristic curve of multiple-contact. The curve can illustrate the character in the miscible and/or near miscible gas injection processes. Based on the curve, we suggest a new model to make an accurate prediction for CO2-oil MMP. Unlike the method of characteristic (MOC) theory and the mixing-cell method, which have to find the key tie lines, our method removes the need to locate the key tie lines that in many cases is hard to find a unique set. Moreover, unlike the traditional correlation, our method considers the influence of multiple-contact. The new model combines the multiple-contact process with the main factors (reservoir temperature, oil composition) affecting CO2-oil MMP. This makes it is more practical than the MOC and mixing-cell method, and more accurate than traditional correlation. The method proposed in this paper is used to predict CO2-oil MMP of 5 samples of crude oil in China. The samples come from different oil fields, and the injected gas is pure CO2. The prediction results show that, compared with the slim-tube experiment method, the prediction error of this method for CO2-oil MMP is within 2%. [ABSTRACT FROM AUTHOR]

For more than three decades, the depleted Rongchang gas reservoir in China's Sichuan Basin was used for the disposal of unwanted water, which resulted in induced earthquakes, with magnitudes as high as 5.2. After all wells were closed, the frequency of seismic activity was observed to decay following a modified Omori law, and since April 2015, seismic activity again began to increase, and a M4.9 earthquake occurred on 27 December. The results of an epidemic‐type aftershock sequence (ETAS) model analysis show that forced seismicity accounted for more than 70% of the total events. For most M ≥ 3.5 earthquakes, including two M ≥ 4 events, the estimated overpressure was lower than the maximum injection pressure. These results, coupled with the fact that postinjection seismic activity has similar characteristics to seismicity during injection, indicate that the injected overpressure fluid was still the driving factor for postinjection seismic activity. Plain Language Summary: Prior to 2013, unwanted water was intermittently pumped into the depleted Rongchang gas reservoir at a depth of 3 km for approximately three decades, inducing many earthquakes with a magnitude up to 5.2. Although all nearby injection wells were closed in 2013, the seismicity in the area has remained relatively high. At this location, M4.9 and M4.0 earthquakes occurred in December 2016. In order to assess the situation, we carried out an integrated study focused on the area's seismicity before and after the injections ceased. The results, including the overpressure required for major earthquakes and various statistical features, suggest that the postinjection seismicity, which was the same as that during injection, was caused by the delayed rupture of preexisting faults within the reservoir and its surrounding faults. Therefore, at an injection site, at which significant injection‐induced earthquakes occurred during injections, there is still a high probability of continuous occurrence of relatively large earthquakes after injection ends. Key Points: Long‐term injection for wastewater disposal into the depleted Rongchang gas reservoir induced earthquakes with magnitudes as large as 5.2After shutting down of injection, seismicity decayed following a modified Omori law with some major eventsPostinjection seismicity demonstrates features similar to that during injection except for a change in event rate [ABSTRACT FROM AUTHOR]

The application of conventional artificial ground freezing (AGF) has two disadvantages: low freezing rate and small frozen range. In this study, a new method with natural cold gas injection was proposed, whereby the shallow soils and water can be frozen rapidly due to the effect of the heat convection. Cold gas from −15 °C to −10 °C, in the winter of northeast China, was injected into the laboratory-scale sand pipe; evolution of the induced frozen front and water migration were studied, and then, the feasibility of the new method was analyzed. According to the evolution of the induced frozen front, the freezing process was divided into an initial cooling stage, phase transition stage, and subcooled stage. The results showed that the increase of initial water content at the beginning of the experiments had little effect on the time required for completing the initial cooling stage, while the time required for the phase transition would increase in nearly the same proportion. In addition, the increase of the cold gas flow rate could not only strengthen the cooling rate of the initial cooling stage but also shorten the phase transition time; thereby, the freezing rate was increased. The freezing rate could reach 0.18–0.61 cm/min in the direction of cold gas flow, and compared to the conventional AGF (months are required for approximately 1 m), the freezing efficiency was greatly improved. [ABSTRACT FROM AUTHOR]

The reservoirs of volcanic rocks in the Junggar Basin of Xinjiang in China are abundant in reserves with potential for exploration and development. They have the characteristics of high heterogeneity and fracture development. The occurrence of bottom water coning is a serious problem during oilfield development, which leads to a rapid increase in the well water cut and greatly affects the reservoir exploitation. In this paper, a visualized model experiment was carded out to simulate the mechanism of nitrogen injection suppression of bottom water coning, based on full diameter core with developed fracture, using X-ray imaging technology and oilfield tests. The research results show that nitrogen injection has a certain effect on suppressing bottom water coning. Nitrogen can block the high-permeability water flow channel, enter the low-permeability area, and improve fluidic', of the crude oil. The timing of nitrogen injection is the main controlling factor affecting gas injection development. Gas injection after a long-term high water cut period is the main reason for the poor ((MCI of suppression of bottom water coning in the oilfield. When the water cut is relatively low, the bottom water suppression effect is better. When the water cut is 70%-80%, the gas injection effect is the best. Moreover, the greater the nitrogen injection pressure and the longer the soak time, the better will be the effect of the bottom water coning suppression. In this paper, a reasonable development strategy of nitrogen injection to suppress bottom water coning is proposed through an experimental study, which is of great significance for guiding the development of volcanic reservoirs in the oiffield. [ABSTRACT FROM AUTHOR]

Copyright of Oil Drilling & Production Technology / Shiyou Zuancai Gongyi is the property of Shiyou Zuancai Gongyi Bianjibu and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

At present, there are many known sources of methane resources in abandoned mine gobs. Therefore, investigations into the characteristics of airflow spatial distributions in abandoned mine gobs will be helpful in future methane drainage processes. In this study, a physical simulation experiment was first adopted to simulate the formation processes of abandoned gobs based on the geological conditions of the abandoned Yongan Mine in China. Gas injection experiments were then conducted to study the gas concentration distributions and variations in a simulated gob based on the measured gas concentrations at certain sampling points. The results indicate that the abandoned gob comprises a gas enrichment zone (GEZ), gas diversion zone (GDZ), and gas isolation zone (GIZ) from the bottom to the top in the incline edges of the abandoned gob, respectively. However, only the GEZ and GIZ exist in the incline center of the abandoned gob. The gas concentration in the GEZ is observed to be the highest, although the concentration is also found to be relatively high in the GDZ. Moreover, a shielding is found to exist between the boundaries of the GEZ and GDZ, which results in a dramatic decline in concentration in the latter due to its extremely low permeability. The study results were verified by using the methane drainage data from the surface vertical wells in the abandoned Yongan Mine. The field application indicated that the methane extraction flow rate could potentially increase by 1.5 times when the well bottom traversed the GDZ and entered the GEZ, compared to the flow rate when the well bottom was located in the GDZ. [ABSTRACT FROM AUTHOR]

Coal seam with low permeability is widely distributed in China. Injection of flue gas (N2:CO2 = 0.85:0.15) is an effective approach to improve coal seam gas drainage efficiency. This process relates complex responses among ternary gases (CH4, CO2, and N2) competitive sorption on coals, gas diffusion, gas‐water migration by means of two‐phase flow, and coal deformation. In this paper, an improved hydraulic‐mechanical model coupling above interactions is established for flue gas injection enhanced gas drainage. This model is used to simulate flue gas enhanced drainage by finite element method. The sensitivity analyses of key factors are made to recovery a better understanding on the processes controlling flue gas enhanced drainage. Results show that the flue gas enhanced drainage can indeed improve the efficiency of gas extraction and reduce the gas pressure to the required value in a shorter duration. Due to the competitive adsorption and gas sweeping effect of injected flue gas, CH4 is driven toward drainage borehole, and CH4 pressure and content near the injection borehole decrease faster than that near the drainage borehole. The peak CH4 pressure laterally moves from the injection borehole to the drainage borehole. Higher injection pressure, initial permeability, and smaller sorption affinity ratios may lead to greater CH4 production rate at early drainage stage, but smaller CH4 production rate at late stage. The factors controlling the behavior of flue gas enhanced drainage are initial permeability, injection pressure, and sorption affinity ratios in order. This work offers useful framework to investigate important technical challenges associated with enhanced mine gas drainage, as well as unconventional gas development. [ABSTRACT FROM AUTHOR]

• Depleted shale gas play provides a promising prospect for H 2 storage compare to other underground storage candidates. • Multi-cycle hydrogen storage feasibility in Longmaxi shale play has been systematically examined through a compositional model. • More than 3 × 108 Sm3 could be recovered in each cycle (equal to 0.54 TWh of power output) through a single shale play pad. Due to the low operation cost, high containment security, and large storage capacity, depleted shale gas reservoirs are considered as promising options for large-scale hydrogen storage. However, its feasibility has not been systematically examined yet. It is still unknown about whether the deliverability (injection/withdrawal) capacity could meet the energy supply/demand and how the depletion time, cushion gas selection, injection/withdrawal strategy will influence the performance of this scenario. Therefore, we present a numerical compositional modelling investigation on hydrogen storage in a partially depleted Fuling shale gas reservoir in China. The results demonstrated that: 1) a high injection/withdrawal capacity could be achieved through a single shale play pad in the area of interest as approximately 5.4 × 108 Sm3 hydrogen could be stored and 3 × 108 Sm3 could be recovered in each cycle (equal to 0.54 TWh of power output). 2) CH 4 production is inhibited once hydrogen storage project is performed, an early depletion time could significantly reduce CH 4 production but slightly improve H 2 withdrawal. 3) Cushion gas injection is beneficial to reducing H 2 loss and enhancing 2.8% H 2 recovery, while the main drawback of this operational measure is an increase in capital cost in gas separation due to lower H 2 purity in the produced gas. This work demonstrates that shale gas reservoir is a promising candidate for hydrogen storage, which is beneficial to the implementation of large-scale hydrogen economy and the operation of hydrogen supply chain. [ABSTRACT FROM AUTHOR]

• NG and COG consumption is computed based on BF mass and heat balance and simulated. • The raceway state is compared as the coal ratio is same and NG and COG are used. • NG injection has more effect on coal reaction behaviors compared with COG. The application of hydrogen-rich gas in the pulverized coal injection technology represents a precious solution to mitigate carbon emissions. In this research, a three-dimensional physical model has been constructed based on the actual dimensions of the gas lance, coal lance, blowpipe, tuyere and raceway of a prominent blast furnace in China. A comparative analysis of the tuyere and raceway status, along with the coal combustion behaviors, is conducted using numerical simulation method after the injection volume of the two hydrogen-rich gases changes. The simulation outcomes demonstrate that the introduction of natural gas into the blast furnace has a comparatively larger influence on the temperature within the raceway, in contrast to the injection of coke oven gas, leading to a more noticeable temperature reduction. Additionally, the average temperature at the tuyere outlet is about 20 K higher with coke oven gas injection compared to natural gas injection under equivalent coal ratios. Furthermore, the burnout of particles is lower in the case of natural gas injection compared to coke oven gas injection. When the injection rates of natural gas and coke oven gas increase, and the coal ratio decreases from 170 kg/t to 140 kg/t, the burnout of coal powder decreases from 68.11% to 64.12% and 64.73%, respectively. The impact of injecting natural gas on coal powder combustion is more pronounced. The research offers a theoretical guide for advancing the mixed application of natural gas, coke oven gas, and particles in the blast furnace, serving as a valuable guide for practical implementation. [ABSTRACT FROM AUTHOR]

Understanding the Debris Bed Formation (DBF) behavior is important to the optimized integral evaluation for Core Disruptive Accident (CDA) of Sodium-cooled Fast Reactor (SFR). Aimed at clarifying the characteristics of flow regimes during DBF, extensive experimental works were carried out by releasing solid particles into a water pool. According to the preliminary studies using bottom heating and nitrogen gas injection, it was found that the effect of coolant boiling should be crucial to the flow-regime transition. However, the gas flow rate considered in these studies (0–50 L/min) was not adequate wide to cover the range of vapor flow rate from the possible drastic boiling in actual CDA of SFR. Therefore, in current study, to elucidate the influence of coolant boiling on DBF flow-regime characteristics more comprehensively and provide more extensive data for supporting the predictive model development, a greater number of experiments are conducted with a much-enlarged range of gas flow rates (up to 100 L/min) under varying parametric conditions (including particle size, particle type, water depth and release pipe diameter). Through analyzing the flow-regime transition, an extended functional form for the effect of coolant boiling is successfully proposed. By incorporating this form into our base model, the model predictability can be extended for the DBF at the conditions of coolant boiling induced by accumulated debris in accordance with the verification of the regime map. Present study is believed to be valuable for further developing and verifying the models and codes for SFR safety analysis in China. • Experiments of debris bed formation in CDA of SFR are conducted with gas injection. • Qualitative observations and varying quantitative parametric analyses are performed. • Effect of coolant boiling induced by accumulated debris is studied and confirmed. • An empirical model extension function is developed based on extensive experiments. • The predictability of the extended model is validated through the regime map. [ABSTRACT FROM AUTHOR]

Copyright of Petroleum Geology & Recovery Efficiency is the property of Petroleum Geology & Recovery Efficiency and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

CO2-enhanced coalbed methane (CO2-ECBM) can not only reduce greenhouse gas by geological storage of CO2 remarkablely, but also increase the recovery efficiency of Clean Coalbed gas. Therefore, it is regarded as a hot global topic, and is a significant approach to realizing the strategy of environment and energy of China. To better utilize coalbeds as the storage space, and to avoid the leakage of CO2 from the sealing site, coalbed and caprock in the pore-pressure limitation must be learnt, infiltrating ability and deforming modulus, etc. Because of the difficulty of underground exploration and inaccuracy of physical simulation, the numerical analysis so far is the main research technique. This paper employed sealing rods as the experimental materials according to their water swelling property, and built the swelling analogy relationship between water-injecting rod and gas-injecting coal. Furthermore, a similarly physical simulation was designed to measure the deformation and stress of coalbed–caprock system so as to provide the testing data for CO2-ECBM engineering. The results show that, based on the quantities analogy of water-swelling materials, all the data measured for the similar coalbed–caprock system are reasonable. In the caprock, a farther location from the injection well contributes a smaller deformation, and the deformation is the negative exponential function of the distance. In our experiment, coalbed strain can reach 10−4 in order of magnitudes, and therefore in the process of gas injection, the magnitude of stress change in the caprock can reach MPa. Finally, gradually upgrading the injecting pressure is a rational technology in the CO2-ECBM engineering. [ABSTRACT FROM AUTHOR]

Highlights • Cumulative-In-Situ-Injection-Production is a novel method for reservoir development. • Simulation results indicate CIIP is an efficient energy-supplement method. • CIIP is applicable to many kinds of tight reservoirs with highly irregular fractures. • Technology for Electric fluid regulation system of CIIP still need to be improved. Abstract Water flooding and gas injection are two traditional secondary development methods for tight oil reservoirs. Water injection has the problem of small injectivity due to low permeable reservoir matrix while gas injection brings about severe breakthrough because of obvious viscosity difference between gas and oil. These traditional approaches that supplement energy between wells are not highly effective. To fill this gap, this paper proposes an efficient energy-supplement method, continuous in-situ injection and production (CIIP), among fractures for multistage fractured horizontal well (MFHW) in tight oil reservoirs. CIIP divides hydraulic fractures into two kinds, in which odd fractures are used for production while even fractures are for injection. CIIP has three main advantages over traditional water flooding: firstly, it switches displacement interval from between injection and production wells to between hydraulic fractures; secondly, CIIP has a better injectivity compared to traditional water flooding at the same injection pressure; and thirdly, CIIP improves sweep efficiency thereby improving oil recovery. In this paper, a workflow is developed to evaluate the performance of CIIP in a case study. Reservoir properties and micro-seismic (MS) mapping data are analyzed to provide fundamental parameters for building a numerical simulation model, and then history matching is achieved to validate the model. The simulation considers two scenarios of hydraulic fractures: the uniform and non-uniform fractures. Uniform-fracture simulation aims to investigate the mechanisms of CIIP under three fracture models; different fracture half-lengths and the situation of existing high permeable channels between injection and production fractures are also included in uniform-fracture simulation. Non-uniform-fracture simulation, whose fractures are interpreted according to MS mapping results, is devised to demonstrate CIIP's superiority in a realistic way. This study is based on a theoretical approach and the results wait to be further proven in the field. Simulation results demonstrate that CIIP is an efficient energy-supplement method. It helps to maintain reservoir pressure near the initial condition during the thirty-year simulation. Meanwhile, even if ten injection wells are added, CIIP still injects 55% more water than water injection (WI) at the same injection pressure. Uniform-fracture simulation indicates that CIIP has a 2.23% more oil recovery than WI and a 3.74% than depletion. Besides, the influence of high permeable channels between injection and production fractures is insignificant and we can still expect CIIP's good performance when hydraulic fractures hit local natural fractures. The non-uniform-fracture simulation demonstrates that CIIP performs well too when hydraulic fractures are randomly distributed. It also finds outs that the presence of primary fractures in which proppant concentrates is essential to CIIP while the role of natural fractures is trivial compared to the hydraulic fractures. In a word, CIIP is a promising technology for tight oil reservoir development. [ABSTRACT FROM AUTHOR]

In order to recover the abandoned coal resource of steeply inclined thin coal seams (SITCS), a field trial of underground coal gasification (UCG) with shaft method has been successfully carried out at Zhongliangshan coal mine in China. Many technological measures have been taken according to the geological conditions of coal seams. These technologies include the hollow-bottom and wall-style gasifiers, pinnate-pattern boreholes, the controlled moving multipoint gas injection, multi-component oxygen-rich gasification agent, and micro-seismic detection of flame working face. Some of the technologies were used for monitoring and controlling the UCG process, including gas-producing conditions and gasifier running states. The trial results show that it’s feasible to recover the abandoned coal resource and produce clean gas energy. The gaseous product of gasification consists of 5–10% H 2 , 14–16% CO and 5–8% CH 4 and generated at a flow rate of 1400–1600 Nm 3 /h with a heat value of 1200–1400 kcal/Nm 3 . [ABSTRACT FROM AUTHOR]

We investigated the 2010 Ms5.1 Suining earthquake (a temporally and spatially isolated event) centred in Moxi gas field in the tectonically stable central region of Sichuan Basin, China. The focal depth is estimated to be approximately 2.8 km and thus the earthquake is nucleated in Triassic marine sediment, coincident with the depths of the top boundary of an overpressured gas reservoir. The strike/dip/rake of the estimated source fault is 223/48/122, showing a rupture area of a dimension of -2.4 km along a blind reverse fault in agree with the geological structures and regional stress regime of this area. Through an integrated analysis, we propose that the associated fault slip of this earthquake was most probably initiated and driven by gas injection from the underlying overpressured reservoir into the shallower gas reservoirs. No aftershocks following the Suining earthquake indicates that the gas injection from the deeper reservoir is somewhat episodic and a fault-valve behaviour. [ABSTRACT FROM AUTHOR]

Vacuum systems for the China Fusion Engineering Test Reactor (CFETR), including pumping system, fueling system, wall conditioning, as well as their control systems, are required to achieve high vacuum, effective plasma fueling, and good wall condition for steady-state plasma operation and to facilitate remote flexible control with high reliability to ensure safe operation. In the last few years, based on the requirements of vacuum systems and subsystems of CFETR, their features and challenges have been analysed, basic parameters have been defined, and preliminary designs have been developed. Herein, nine cryopumps with pumping speed of 68 m³/s for D 2 in a molecular flow regime are proposed for use in a torus vacuum chamber to achieve vacuum pressure <1.0 × 10−5 Pa before plasma operation. The throughput of the torus pumping system is designed to be >290 Pa•m³•s−1 to meet the requirement of steady-state operation of CFETR discharge. Pellet injectors and the gas injection system for seeding the fuel and impurity gas and wall conditionings, including baking, GDC, and ICRF-DC, for removal of hydrogen isotopes/impurities of the torus vacuum are also designed. Moreover, integrated design of vacuum systems and space layout of all subsystems are also investigated. [ABSTRACT FROM AUTHOR]

Highlights: [•] A static and dynamic model is presented for a producing CBM field in Qinshui Basin, China. [•] Dynamic model is history matched using the 16-month field data of 43 CBM wells. [•] A new purpose-build economic model is presented. [•] Well spacing for CBM production is optimised based on an integrated techno-economic approach. [•] Feasibility of ECBM for various injection gas compositions, injection timing, gas price and carbon credits is studied. [Copyright &y& Elsevier]

Pre-gas drainage plays a significant role of preventing gas disasters in underground coal mines. However, it is difficult to reduce the gas content to below the threshold values, especially in low permeability coal seams in China. Previous field trials on the enhanced coalbed methane recovery (ECBM) by nitrogen injection mostly focused on the ground. Until now, few attempts on N 2 injection to enhance coal seam gas drainage (N 2 -ECGD) and no sufficient evidences can indicate the good effect. In this study, exploratory tests of N 2 -ECGD were carried out in underground low-gas coal seams (with gas content less than 5 m3/t). An experiment to displace the CH 4 in coal by N 2 injection under constant pressure conditions was first carried out. The results show that continuous N 2 injection can promote the desorption of CH 4 in the coal pores, which cannot be achieved under normal pressure. N 2 -ECGD field trials were conducted in the working face of a coal mine in Hejin City, Shanxi Province, China. The effective pressure of N 2 injection (EPI) was investigated. Intermittent and continuous N 2 injection trials were carried out to study the response characteristics of the gas flow rate, CH 4 concentration, and flow rate. The results show an EPI of 0.45 MPa and gas injection radius of 5 m. The gas flow rate increased significantly after N 2 injection. Although the CH 4 concentration decreased, the CH 4 flow rate remained high. On the basis of the change characteristics of gas drainage parameters, the physical process of N 2 -ECGD was analyzed. The research results obtained in this study can serve as a reference for the application of N 2 -ECGD in low permeability coal seams. The study also provides a new technical approach for local gas prevention and control in underground coal mines. • Laboratory experiments on CH 4 single diffusion and N 2 injection to displace CH 4 were carried out. • N 2 -ECGD field trials were conducted on an underground coal seam with a gas content of less than 5.0 m3/t. • The effective pressure of N 2 injection in the trial coal seam was determined. • The physical process of N 2 -ECGD was analyzed. [ABSTRACT FROM AUTHOR]

• A method is proposed to imitate CO 2 sequestration in gas reservoirs with aquifer. • CO 2 -brine-rock interaction causes the change of formation properties inevitably. • The formation damage in gas zone is severer than that in water zone. • The negative impact on formation properties is minor in good-quality reservoir. • The strategy is offered to ensure CO 2 sequestration in gas reservoirs with aquifer. To understand the impact of CO 2 -brine-rock interaction on formation properties and the differences between gas zone and water zone, dynamic and static experiments were conducted under gas reservoir conditions to imitate the process of CO 2 injection and storage in gas reservoirs with aquifer. In this work, core plugs, rock debris and brine are taken from DF gas field, a giant gas reservoir with aquifer in the South Sea of China. Meanwhile, scan electron microscope (SEM), energy dispersive spectrum (EDS), X-ray diffraction (XRD) and flame atomic absorption spectrometry (FAAS) were also applied to analyze the mechanism of property alterations of brine and rock minerals due to CO 2 -brine-rock interaction. Results show that CO 2 -brine-rock interaction occurs in both gas zone and water zone since water evaporates into gas stream and CO 2 dissolves into brine to form carbonic acid. CO 2 -brine-rock interaction can cause rock minerals dissolution and to fall from the matrix to form free particles suspending in pore space filled with fluids and flow along with them. It generally triggers sharp reduction of formation permeability and leads to negative impact on CO 2 injectivity and storage. And the formation damage in gas zone is severer than that in water zone. Meanwhile, CO 2 -brine-rock interaction in good-quality reservoir in water zone can improve porosity and permeability to further enhance CO 2 injectivity and storage capacity. Thus, dry CO 2 should be preferentially injected into aquifer with good formation properties to weaken negative effect to ensure CO 2 successful injection and storage in gas reservoirs with aquifer. This work also provides a reference for designing technical scheme of CO 2 injection and storage in gas reservoirs with aquifer. [ABSTRACT FROM AUTHOR]

Considering the worldwide development of tight and ultra-tight oil reservoirs, the increasing demand for fossil energy and long-term environmental concerns regarding large CO 2 emissions, application of dual-purpose carbon dioxide (CO 2) sequestration/enhanced oil recovery in oil reservoirs has gained considerable attention [1,2]. However, unlike its mature application in conventional reservoirs, the effectiveness of CO 2 EOR and geological sequestration in tight reservoirs is still under investigation [3]. In this work, we investigated the efficiency of different injection strategies on simultaneous CO 2 EOR and storage in ultra-low permeability (<1 milli-Darcy) [4] core samples from Yanchang Formation in the Ordos Basin, China. Three injection strategies were tested including gas continuous flooding, water alternative gas injection, and cyclic gas injection. Core-flooding experiments under immiscible and miscible conditions were conducted. Furthermore, to investigate underlying mechanisms of oil recovery and carbon storage in tight cores, interfacial tension tests, viscosity measurements, contact angle measurements, and constant composition expansion tests were performed using reservoir rock and fluids. We found that water alternative gas injection was superior to continuous gas injection in achieving the goal of simultaneous high oil recovery and high CO 2 storage. However, cyclic CO 2 injection provided the most efficient strategy for enhanced oil recovery in the tight rocks studied in this work with a comparatively higher gas storage capacity than the other injection strategies. [ABSTRACT FROM AUTHOR]

• O 2 is brought into the well during the injection of N 2 , resulting in oxygen corrosion. • The serious corrosion is resulted in O 2 by greatly promotes the cathodic process. • The perforated screen failed because of the serious oxygen corrosion. The perforated screens of a gas injection huff and puff well broke down in an oilfield in western China. The physical and chemical properties of the failure-perforated screens met the requirements of relevant technical protocols. The injected gas was nitrogen produced by the membrane nitrogen method, which contains approximately 5% O 2. Therefore, a substantial amount of O 2 entered the well during the gas injection, and greatly promoteed the cathodic process of the electrochemical corrosion. High salinity formation water, especially with large amounts of Cl-, further accelerated the corrosion. The significant oxygen corrosion under the well finally led to the failure of the perforated screen. [ABSTRACT FROM AUTHOR]

Fractured-vuggy carbonate reservoir played a significant role in unconventional reservoirs, but it was difficult to be developed due to its complex reservoir types. Therefore, it was crucial to find a suitable development program to enhance oil recovery. In this work, a two-dimensional visual physical model of fractured-vuggy reservoir was designed and fabricated according to actual geological data and injection-production characteristics of a representative fractured-vuggy carbonate reservoir, Tahe Oilfield in China. Nitrogen flooding experiment, nitrogen flooding under the high gas energy experiment, nitrogen flooding under strong bottom water energy experiment and foam assisted nitrogen gas flooding experiment were carried out respectively by using two-dimensional visual model. The flow behaviors and the main mechanisms for enhanced oil recovery were revealed by analyzing the oil displacement performance in the visual physical model. Experiment results showed that the gas cap energy and the bottom water energy played a synergistic effect in the nitrogen flooding. The stronger the bottom water energy was, the larger the gas spread area was, and the increase of oil recovery would be very high. If the gas injection rate was too strong, the dominant gas flow channel would be formed prematurely, and the oil recovery was little increase. In addition, foam could effectively control the gas mobility, delay the formation of gas channeling. Meanwhile, the oil recovery of foam assisted nitrogen gas flooding was higher 12% than that of nitrogen flooding. Therefore, the mechanism for improving the degree of development was obtained mainly through gravity differentiation to form the secondary gas top and realize the development of the remaining oil. • A two-dimensional visual physical model of fractured-vuggy reservoir was designed and fabricated. • The flow behaviors and the main mechanisms for nitrogen and foam assisted nitrogen gas flooding were studied. • The oil recovery of foam assisted nitrogen gas flooding was higher 12% than that of nitrogen flooding. [ABSTRACT FROM AUTHOR]

In 2017, China successfully conducted its first offshore gas hydrate production test by using vertical well in the Shenhu area, achieving a total gas production of 3.09 × 105 m3. However, there is still a long way to commercial production. In this study, to evaluate and improve the gas production potential of China's first hydrate production site, depressurization, and the combination of depressurization and hot water injection, were applied to natural gas hydrate (NGH) reservoir in China's first offshore hydrate production site to analyze 10 years' hydrate production features. The results indicated that the decomposition front of hydrate when using depressurization in two horizontal production wells had obvious non-uniform characteristics, and there were rapid decomposition regions and hydrate reformation regions. Among them, the hydrate reformation region may have adverse effects on hydrate decomposition. The combination of depressurization and hot water injection could improve total gas production and alleviate hydrate reformation. However, when the temperature of hot water injected increased from 35 °C to 80 °C, the energy efficiency decreased from 10.22 to 1.53, as a lot of energy was consumed to heat the sediments in the reservoir. When the hot water injection time was reduced from 3650 days to 1825 days, the energy efficiency could be effectively increased from 10.22 to 21.78 without significant reduction of the gas production. This work contributed to the present understanding of production behavior of depressurization and the combination of depressurization and hot water injection, and helped to evaluate the influence of hot water injected on gas production from NGH reservoir. • Rapid decomposition region and hydrate reformation region coexist near the decomposition front. • Increasing hot water injection temperature 35 °C–80 °C will reduce energy efficiency from 10.22 to 1.53 • The reduction of hot water injection time from 10 years to 5 years will not significantly reduce gas production. [ABSTRACT FROM AUTHOR]