High Injection Rates Research Articles

Experimental Investigation of the Impact of Particle Size on Its Distribution within a Horizontal Wellbore.

Fracture conductivity is directly affected by an uneven proppant distribution, which affects the productivity of a well. The distributions of 40/70 mesh white sand compared to 100 mesh brown sand in a horizontal wellbore were investigated in this study. The apparatus used to conduct these tests was a 30 ft-long transparent horizontal wellbore with three perforation clusters. The proppant distribution was examined experimentally by injecting slurries at three different injection rates ranging from 20 to 75 gpm. The proppant concentration of both sands increased for each test from 0.5 to 2 ppg. The proppant concentrations and injection rates were used with multiple perforation configurations (orientations) including extreme limited entry perforations. The results confirmed that the injection rates significantly affected the proppant distributions across the different perforation clusters. Even distribution of the 40/70 mesh sand can be obtained using a 1 shot per foot (SPF) top perforation design. The 100 mesh sand was evenly distributed using a 4 SPF perforation configuration. The settling percentage was calculated for each experiment to determine the quantity of 40/70 mesh and 100 mesh sand settled at the bottom of the horizontal wellbore. A carrier fluid can suspend the sand more effectively with a higher injection rate, reducing the average sand settling to 2% in the case of the 100 mesh sand compared with approximately 8% for the 40/70 mesh sand at similar injection rates. This research confirms the need to use a 100 mesh at high injection rates to reduce sand settling during the hydraulic fracturing process.

Insights into the intimate link between nonlinear rheological characterization and the rupture behavior of polymer gel in model fractures

A deep understanding of how fluid flows through the polymer gels has significant implications for achieving effective gel treatments in fractured reservoirs. This study aims to investigate the behavior of brine breakthrough from the gels in model fractures and relate the rupture behavior to the rheological properties of the gels. The underlying mechanisms for different gel rupture behavior are also elaborated. The effect of the injection rates, the aperture of tubes, and the gel properties on the rupture pressure of the gel were also studied. The results show that the rupture pressure of gel is highly dependent on the flow rates, and the rupture pressure is decreased with increasing the aperture sizes. It is also found that the polymer gel with a higher amount of crosslinkers has a high G’ value yet exhibits a low rupture pressure. From the visualization experiments, we found that brine is more likely to penetrate through the gel along the weak network structures, and a narrower channel would be formed at a higher injection rate. Moreover, various rheological measurements were conducted to characterize the gel properties. The results reveal that the maximum differential pressure the gel can withstand is highly dependent on the microstructure and the toughness of the gel. The defect structures, such as large cavities or cracks, would lead to a low yield stress of polymer gel, which is more susceptible to fracturing. The texture properties of the polymer gel can be interpreted by the shapes of Lissajous curves. The flexible gel shows a “banana-shaped” curve at high strain, a typical response for rubber-like materials. The toughness of the gel can significantly improve the pressure for water breakthrough. The degree of the brittleness of the polymer gels can be characterized by the reduction rate of the maximum elastic stress. The results presented in this study allow us to select an appropriate gel for water shutoff in fractured reservoirs by rheological methods, which are more robust and cost-effective.

Optimizing contrast protocol for bone-subtraction CT angiography of intracranial arteries in normal dogs using 160-slice CT.

Bone-subtraction computed tomography angiography (CTA) (BSCTA) is a new technique designed to overcome the limitation of three-dimensional CTA, where the vessels surrounded by bone and calcification can be obscured. An optimal contrast CT protocol for intracranial artery visualization with BSCTA has yet to be established in dogs. The purpose of this study was to determine the optimal contrast protocol of CTA for visualizing intracranial artery using an automatic bone-subtraction technique in dogs. Brain CTA was performed four times for each of nine healthy beagle dogs to cover all the contrast protocols: two different contrast iodine concentrations (300 and 370mgI/mL) and two different contrast media injection rates (2 and 4mL/s). Bone removal post-processing was performed automatically by subtracting the non-enhanced CT data from the contrast CT data using a dedicated workstation. The bone-subtracted intracranial vessels were analysed for quantitative and qualitative evaluation. Quantitative evaluation showed significantly higher CT attenuation values for the group with a 370mgI/mL iodine content at a rate of 4mL/s than the two groups with a 300mgI/mL iodine content at the rates of 2 and 4mL/s (p<0.001). Qualitative assessment revealed significantly higher mean scores for the 370mgI/mL groups than the 300mgI/mL groups and significantly higher mean scores for the 4mL/s groups than the 2mL/s groups (p<0.05). The optimal contrast protocol for BSCTA suggests that high iodine material concentration and high injection rate should be used for strong arterial attenuation and great visualization of the intracranial arterial structure in dogs.

A kinetic study of black hole activation by local plasma injection into the inner magnetosphere

ABSTRACT An issue of considerable interest in the theory of jet formation by the Blandford–Znajek mechanism, is how plasma is being supplied to the magnetosphere to maintain force-free conditions. Injection of electron–positron pairs via annihilation of MeV photons, emitted from a hot accretion flow, has been shown to be a viable possibility, but requires high enough accretion rates. At low accretion rates, and in the absence of any other form of plasma supply, the magnetosphere becomes charge-starved, forming intermittent spark gaps that can induce intense pair-cascades via interactions with disc radiation, enabling outflow formation. It is often speculated that enough plasma can penetrate the inner magnetosphere from the accretion flow through some rearrangement of magnetic field lines preventing the formation of spark-gaps. To address this question, we conducted a suite of 2D axisymmetric general-relativistic particle-in-cell simulations, in which plasma is injected into specified regions at a predescribed rate. We find that when pair-production is switched off, nearly complete screening is achieved when plasma is injected at the entire region inside the outer light cylinder at a high enough rate. Injection outside this region results in either, the formation of large vacuum-gaps, or coherent, large-amplitude oscillations of the magnetosphere, depending on the injection rate. Within our allowed dynamical range, we see no evidence for the system to reach a steady-state at high injection rates. Switching on pair-production results in nearly complete screening of the entire magnetosphere in all cases, with a small fraction of the Blandford–Znajek power dissipated as TeV gamma-rays.

Investigation of Natural Weak Interface Properties and Their Impact on Fracture Propagation in Shale Reservoirs

Horizontal well multi-cluster fracturing technology is crucial for the economic development of fractured shale reservoirs. The abundance of natural fractures in shale reservoirs significantly influences the propagation path of hydraulic fractures and determines the formation of complex fracture networks. To investigate the impact of natural weak planes on the geometric parameters of fractures in shale reservoirs, we first conducted tests on the mechanical characteristics of core samples from outcropping shale in the Weiyuan area using the indoor three-point bending method and digital image correlation (DIC) technology, providing data validation for subsequent numerical models. Secondly, considering the interaction between hydraulic and natural weak planes in three-dimensional space, we established a three-dimensional numerical model for horizontal well fracturing to simulate the synchronous competition and expansion of fractures in multi-cluster fracturing. Based on this foundation, we analyzed the influence of formation parameters and engineering parameters on the formation patterns of complex fracture networks. The results indicate that the difference in in situ stress is a significant factor affecting the selection of fracture propagation paths. As the in situ stress difference increases, it becomes more challenging to open natural fractures, leading to a reduced probability of activation of natural weak interfaces. When the cohesive strength of natural fractures is smaller, they are more likely to open and capture hydraulic fractures, thereby increasing shear slip length and fracture network area. Each fracturing stage has an optimal perforation density combination, where a higher density of perforations leads to reduced perforation pressure drop and weaker ability to mitigate inter-cluster stress interference. To achieve a comprehensive and balanced development of multi-clusters, the inter-cluster stress interference can be alleviated by increasing the perforation pressure drop. For dense perforation clusters, higher injection rates and viscosity can be employed to ensure the uniform development of multiple perforation clusters. This study provides new insights into predicting the formation of complex fracture networks in shale reservoirs and offers valuable guidance for optimizing hydraulic fracturing designs.

The injection-production performance of an enhanced geothermal system considering fracture network complexity and thermo-hydro-mechanical coupling in numerical simulations

The effect of fracture networks on EGS performance remains worth further investigation to guide the formulation of geothermal extraction strategy. We established models that account for thermo-hydraulic-mechanical (THM) coupling and that are based on the framework of discrete fracture network (DFN) to evaluate the heat extraction performance in deep-seated fractured reservoir. Our numerical results reveal that the zones of temperature, pressure, and stress perturbation diffuse asynchronously during the circulation of injection-production, and the stress perturbation always lags behind the other two. Furthermore, the effects of the fracture network characteristics including randomness, geometry, length, aperture, and injection parameters on the heat production are quantitatively investigated. Under the same number of fractures, different network geometry leads to different EGS production performance, the network with horizontal fracture set shows better thermal extraction performance but poor injection performance, which is because the fracture dip affects the thermal evolution on the horizontal plane. The effect of fracture length on EGS performance highly depends on its orientation, the excessive increase of fracture length towards injection-production wells is detrimental to heat extraction. The fracture aperture affects the working fluid transport and thus the EGS performance, the fractured reservoir with smaller fracture aperture shows the worse fluid flow performance but the better geothermal extraction performance, thus we believe that the optimal fracture aperture should be kept at a level of 0.5–1.0 mm in a self-propping fractured granitic system. The main influence of injection parameters on thermal extraction from the fractured reservoirs is the injection mass rate, because a high injection rate results in significant solid responses, including failure stress concentration, decreased safety factor, and increased permeability, which occur in those fractures that are originally connected to the injection well. These results of our research and the insights obtained have important implications for deep geothermal geoengineering activities.

Numerical Investigation of Influential Factors in Hydraulic Fracturing Processes Using Coupled Discrete Element‐Lattice Boltzmann Method

AbstractHydraulic fracturing is widely used to stimulate unconventional reservoirs, but a systematic and comprehensive investigation into the hydraulic fracturing process is insufficient. In this work, a discrete element‐lattice Boltzmann method is implemented to simulate the hydro‐mechanical behavior in a hydraulic fracturing process. Different influential factors, including treatment parameters (injection rates and fluid viscosity), formation parameters (in situ stress states and natural fractures) and rock properties (heterogeneity of rock strengths and rock permeability), are considered and their impacts on the initiation and propagation of hydraulic fractures are evaluated. A higher injection rate, increased viscosity, and larger in situ stress will lead to an increase in the initiation pressure. Conversely, higher formation permeability and a greater degree of heterogeneity in bond strengths will result in a decrease in the initiation pressure. The complexity of generated fractures is significantly influenced by the injection rate and degree of heterogeneity. However, fluid viscosity, in situ stress states, and formation permeability individually do not affect the geometrical complexity. Shear displacement can occur during a hydraulic fracturing process due to increased pore pressure and variations in in situ stress caused by injected fluid. Low‐viscosity fluid with a high injection rate can have a significant pressure buildup and generate complex fracture networks in low‐permeability heterogeneous formations. Natural fractures can significantly impact the complexity of generated fractures, while more in‐depth research is required regarding complex natural fracture distributions.

Multi-stage and multi-well fracturing and induced stress evaluation: An experiment study

Multi-stage and multi-well fracturing of horizontal wells are indispensable techniques in developing shale oil and gas. Increasing the stimulated reservoir volume (SRV) is of vital importance for production. However, further research is still required due to the uncertainty of fracture propagation mechanism and the evolution of induced stress. To date, there are few true triaxial hydraulic fracturing physical simulations of large-natural shale samples. By using 13 cubic shale samples (30 × 30 × 30 cm), we investigated the effect of in-situ stress, treatment parameters, and different patterns of multi-well fracturing (staggered or tip-to-tip) on fracture propagation. The pumping pressure data is collected, and the evolution data of the induced stress is measured by a strain gauge which is glued on the rock surface. The fracture geometry is analyzed based on post-fracturing reconstruction, the fracturing data, and the induced stress evolution data. Finally, the suggestions for improving multi-stage and multi-well fracturing treatment are proposed. The results show that: A low overburden stress makes the bedding plane easier to be opened, and it also stops the main hydraulic fracture propagating to the deep reservoir. A high injection rate generates higher net pressure in fracture, and the hydraulic fracture can propagate and cross the bedding plane easily. While using a low injection rate, the liquid can only leak along the bedding plane near the wellbore, leading to a simple fracture geometry. The more fracturing stages, the more complex the fracture network is, and the induced stress data shows an obvious increase. The addition of temporary plugging agent causes a significant increase in pumping pressure and induced stress curves, and the fracture geometry is more complex. Compared with the experiment that has no temporary plugging agent, the induced stress has an increase of 0.7 MPa. In multi-well fracturing experiments, the type of multi-well fracturing (staggered or tip-to-tip) plays an important role on fracture propagation: The fracture complexity in tip-to-tip pattern is significantly lower than that in fracturing staggered pattern because of the “frac-hit”. The longer time interval between treating two wells, the lower the induced stress and the more regular fracture geometry. Further, the fractures that generated in the first well will be reopened by the fluid from the second well when the “frac-connection” occurs between the two wells, causing the induced stress to rise again. The results may provide a reference for the multi-stage and multi-well fracturing design.

Correlating Impacts of Injected Fuels on Carbon Emissions in Blast Furnace with Computational Fluid Dynamics Modeling

A major challenge for steelmaking is the reduction of CO2 emissions. In this regard, the blast furnace (BF) is critical due to the high associated CO2 levels. This investigation assesses the impact of tuyere‐injected fuels on BF CO2 emissions. Specifically, computational fluid dynamics results obtained previously at Purdue University Northwest are analyzed to obtain CO2 emissions when natural gas (NG), syngas, hydrogen, or hydrogen/NG are injected. CO2 emissions are compared with those produced when 95 kg of NG/thm is injected. Among these scenarios, the largest CO2 reduction occurs when 102 kg of syngas/thm (COG feedstock #1) is injected at 973 K, reducing CO2 by 190.6 kg thm−1. The largest CO2 reduction obtained with NG occurs when 130 kg thm−1 is injected at 600 K, reducing emissions by 65 kg thm−1. H2 injection also reduces CO2, but requires careful adjusting to reach stable operation. For instance, injecting 35 kg of H2/thm reduces CO2 by 52 kg thm−1. Increasing gaseous injection rates can significantly reduce CO2 emissions, with fuel preheating providing an addendum, but high injection rates can lead to unstable operation. Furthermore, results show a correlation between CO2 emissions and average temperature of shaft region for multiple fuels and injection conditions.

Experimental study of the temporary plugging capability of diverters to block hydraulic fractures in high-temperature geothermal reservoirs

The effective plugging of artificial fractures is key to the success of temporary plugging and diverting fracturing technology, which is one of the most promising ways to improve the heat recovery efficiency of hot dry rock. At present, how temporary plugging agents plug artificial fractures under high temperature remains unclear. In this paper, by establishing an improved experimental system for the evaluation of temporary plugging performance at high temperature, we clarified the effects of high temperature, injection rate, and fracture width on the pressure response and plugging efficiency of the fracture. The results revealed that the temporary plugging process of artificial fractures in hot dry rock can be divided into four main stages: the initial stage of temporary plugging, the bridging stage of the particles, the plugging formation stage, and the high-pressure dense plugging stage. As the temperature increases, the distribution distance of the temporary plugging agent, the number of pressure fluctuations, and the time required for crack plugging increases. Particularly, when the temperature increases by 100 °C, the complete plugging time increases by 90.7%.

Numerical simulations of supercritical carbon dioxide fracturing: A review

As an emerging waterless fracturing technology, supercritical carbon dioxide (SC-CO 2 ) fracturing can reduce reservoir damage and dependence on water resources, and can also promote the reservoir stimulation and geological storage of carbon dioxide (CO 2 ). It is vital to figure out the laws in SC-CO 2 fracturing for the large-scale field implementation of this technology. This paper reviews the numerical simulations of wellbore flow and heat transfer, fracture initiation and propagation, and proppant transport in SC-CO 2 fracturing, including the numerical approaches and the obtained findings. It shows that the variations of wellbore temperature and pressure are complex and strongly transient. The wellhead pressure can be reduced by tubing and annulus co-injection or adding drag reducers into the fracturing fluid. Increasing the temperature of CO 2 with wellhead heating can promote CO 2 to reach the well bottom in the supercritical state. Compared with hydraulic fracturing, SC-CO 2 fracturing has a lower fracture initiation pressure and can form a more complex fracture network, but the fracture width is narrower. The technology of SC-CO 2 fracturing followed by thickened SC-CO 2 fracturing, which combines with high injection rates and ultra-light proppants, can improve the placement effect of proppants while improving the complexity and width of fractures. The follow-up research is required to get a deeper insight into the SC-CO 2 fracturing mechanisms and develop cost-effective drag reducers, thickeners, and ultra-light proppants. This paper can guide further research and promote the field application of SC-CO 2 fracturing technology.

Hydraulic Fracture Propagation and Proppant Transport Mechanism in Interlayered Reservoir

Hydraulic fracture is crucial for assuring well production from unconventional reservoirs. For the optimization of hydraulic fracture geometry and the ensuing production of an interlayered reservoir, vertical hydraulic fracture propagation path has been analyzed. However, an effective fluid channel cannot be formed if the proppant is unable to reach the area where the fracture propagates. This paper presents a numerical model using the lattice-based method to investigate the hydraulic fracture propagation and proppant transport mechanism in interlayered reservoirs. The hydraulic fracture propagation model was simulated under different geological and fracturing engineering factors. The results indicate that interlayer Young’s modulus and horizontal stress anisotropy are positively correlated with longitudinal propagation and proppant carrying ability in interlayered formations. The fracturing injection rate has an optimal solution for fracture propagation and proppant carrying since a too low injection rate is unfavorable for fracture penetration of the interlayer, while a too high injection rate increases fracture width instead of further fracture penetration. In conclusion, attention is drawn to fine particle size proppants used in multi-layer reservoirs for fracturing fluid to carry proppants as far as possible to obtain maximum propped area.

An innovative approach to the improved radiating divertor concept by supersonic molecular beam injection on HL-2A

The ‘puff-and-pump’ radiating divertor condition is a promising approach for the reduction of excessive thermal power loading on the divertor targets. The divertor supersonic molecular beam injection (SMBI) system installed on HL-2A strongly enhances the capacity of the divertor heat load control. This system has a faster time response than the divertor gas puffing (GP) system. Divertor heat load control capacity has been compared between these two techniques by experiments on HL-2A and simulations. Experimental results suggest that the divertor SMBI system reduces the divertor heat flux peak to a lower level with less time delay than that for the divertor GP system, owing to a higher injection rate and particle velocity. Simulations by SOLPS demonstrate that a high injection rate shortens the function time which is defined by the time interval between the arrival of the particles at the divertor plasma edge and the reduction of divertor electron temperature. High velocity of SMBI injected neutral gas particle also shortens the particle flight time to arrive at the edge. Less flight time and function time lead to a faster response of the divertor SMBI system compared to the divertor GP system. In addition, simulations by EMC3-EIRENE also suggest that, compared to the GP system, stronger heat load reduction of the SMBI system can also be caused by deeper deposition of gas source owing to its higher particle velocity.

Numerical Tracking of Natural Gas Migration in Underground Gas Storage with Multilayered Sandstone and Fault-Bearing Caprocks

The structure of caprocks is often greatly altered by different scales of faults or fissures in long-term geological tectonic evolution, and the sealing performance may be deteriorated. In this paper, a simplified geological model characterized as multilayered sandstone and fault-bearing caprocks extracted from the Shuang 6 underground gas storage located in the Liaohe oilfield was established. Different fault geometry (e.g., fault length, fault dip angle, and fault type) and seepage attributes (porosity and permeability) were considered to illustrate their impacts on natural gas migration during the cyclic high rate of injection and production of natural gas. The results showed that the seepage anisotropy and the natural gas front are strongly affected by the formation properties and, especially, are hindered by the low permeability sandstone layers. The difference in the lateral migration distance of natural gas in different layers can reach 110 m at the end of the injection period, with an annual injection volume of 108 m3. The migration of natural gas along the fault zone is mainly controlled by the permeability of faults, followed by fault scale, fault dip angle, and fault type. The sealing failure of caprocks in the fault zone does not occur based on the simulated gas migration distribution, showing that a very limited amount of natural gas migrates into the caprocks.

Gas fracturing behavior and breakdown pressure prediction model for granite under different confining pressure and injection rate

Conventional hydraulic fracturing techniques are often found problematic for extracting geothermal energy in hot dry rock (HDR). As an alternative, employing the less viscous gas to replace water as the fracturing fluid showed great potential for more effective fracturing of HDR. In this work, the failure behavior and mechanism of granite during gas fracturing under different confining pressures and gas injection rates are comprehensively examined. It is shown that the breakdown pressure increases with the increase of confining pressure, whereas higher gas injection rate can result in evident decrease of the breakdown pressure. As the confining pressure grows, the acoustic emission (AE) event increases rapidly, with much higher AE counts observed at high gas injection rates than at low injection rates. Comparatively, the AE energy decreases under high confining pressure, due probably to granite transitioning from brittle to ductile. It is interesting that the b-value of AE varies dramatically as the gas injection rate becomes higher with significant fluctuations, indicating the ratio of large fracture and small fracture changes drastically during gas fracturing. In addition, the length of the induced fractures decreases with the increase of confining pressure during gas fracturing, and the length and width of vertical fractures are evidently larger when at high gas injection rate. Last, a novel theoretical predictive model is proposed for estimating breakdown pressure during gas fracturing based on the average tensile stress criteria, which is featured by considering the effect of confining pressure and gas flow behaviors. The theoretical prediction agrees with the experimental results. The present study can provide valuable results for theoretical analysis and engineering applications of gas fracturing in stimulating the HDR reservoirs.

Impact of Hydrogenous Gas Injection on the Blast Furnace Process: A Numerical Investigation

Intensifying hydrogen use in the blast furnace is a key technology for significant coke and CO2 emissions reductions. The most straightforward approach is the implementation of high hydrogenous gas injection rates in the BF tuyeres. Yet this solution has not been widely implemented due to a lack of understanding of the impact on the furnace’s internal state. In this paper, a newly developed BF mathematical model is presented and validated on operation data. The model is next applied to investigate the effect of hydrogenous gas injection on the overall performance and internal state of the furnace. The current state of an industrial BF is used as a starting point, increasing the injection of coke oven gas, natural gas or pure H2 to the maximum where the limits for a safe and stable process are still obeyed. All three gases were found capable of significantly decreasing the coke rate, but only coke oven gas and pure H2 allowed for a significant reduction of the CO2 emissions. It was found that the indirect reduction of H2 is intensified by hydrogen enrichment partially at the expense of indirect reduction by CO. Furthermore, the water gas shift reaction is intensified at increased hydrogenous gas injection, affecting the CO and H2 utilization of the top gas. The study gives an insight into the feasibility of BF processes with high hydrogenous gases injection into the tuyeres and the resulting coke savings.

Parameters Variation and Flow Characteristics When CO2 Displacing Brine in Four Micromodels Simulating Carbon Sequestration in Saline Aquifers

Two-phase flow of CO2/brine in porous media is critical to the capacity and safety of carbon sequestration into the brine aquifer. In order to provide valuable information and important theoretical basis for site selection and CO2 injection, the microscopic visualization technology was employed in this study to conduct displacement experiments of CO2/brine at the pore scale. Four micromodels with different sizes and structures, five injection rates of CO2, and six salinities of brine were used to study the effects of micromodel’s structure and displacement pattern on two-phase flow. Several parameters including the differential pressure, contact angle, permeability, velocity field, and force field were obtained by experimental measurement, image post-processing, and theoretical analysis, and then, these parameters’ variation was investigated. Phenomena such as thin film, corner flow, and Haines jump were also found during the displacement. Although brine could be completely displaced by CO2 in the capillary duct, the backflow of the wetting phase would occur at a low injection rate. Phenomena different from the theoretical analysis also occurred in pore doublet models: some brine was residual in the homogeneous pore doublet model at a low injection rate, while the heterogeneous pore doublet model was fully occupied by CO2 at a high injection rate. These phenomena are very useful for two-phase flow, and multiple factors need to be comprehensively considered to determine the operating conditions of CO2 storage into the brine aquifer.

Current status and development trends of CO2 storage with enhanced natural gas recovery (CS-EGR)

CO2 storage with enhanced gas recovery (CSEGR) technology is a pivotal solution to mitigate the greenhouse effect and respond to national energy conservation and emission reduction policies. This involves injecting CO2 into gas reservoirs for storage and using it to displace gas into producing wells to enhance production. This paper provides a comprehensive analysis of the primary mechanisms of CO2 storage in gas reservoirs, quantifies the long-term contribution of these, and summarizes the methods used to evaluate CO2 storage potential. The mechanisms of the displacement of natural gas by CO2 are explained and two technical difficulties are addressed: the degree of CO2-natural gas mixing and competitive adsorption and displacement of CO2-CH4. Besides, the main factors affecting CSEGR are studied thoroughly, and the currently typical CSEGR field pilot tests across the word are considered along with CSEGR economic policy research. This paper then identifies the current challenges and future trends in CSEGR development. The results show, firstly, in the later stage of gas reservoir development, high rates of CO2 injection at the bottom of the gas reservoir and CH4 production at the top can significantly enhance gas recovery. Secondly, in previous studies, the degree of CO2-natural gas mixing has been studied more in sandstones and carbonates, while CO2-CH4 competitive adsorption has been studied more in shales and coal seams. The results of all these studies demonstrate the feasibility of CSEGR. Thirdly, Four major storage mechanisms interact to stabilize CO2 storage in gas reservoirs, but there is no systematic method to evaluate the CO2 storage potential. Finally, among recent experimental and simulation studies, CSEGR analytic techniques that consider complex formation conditions need to be further explored. Additionally, combining CSEGR with geothermal energy development in high temperature gas reservoirs presents a promising avenue for exploration.

Modeling Flow and Transport in Saline Aquifers and Depleted Hydrocarbon Reservoirs for Hydrogen Energy Storage

Summary Hydrogen (H2) is an attractive energy carrier, and its true potential is in decarbonizing industries, such as for providing heat for buildings and being a reliable fuel for trains, buses, and heavy trucks. Industry is already making tremendous progress in cutting costs and improving the efficiency of hydrogen infrastructure. Currently, heating is primarily provided by using natural gas and transportation by gasoline with a large carbon footprint. Hydrogen has a similarly high energy density, but there are technical challenges preventing its large-scale use as an energy carrier. Underground geologic storage of hydrogen in porous media (aquifers and hydrocarbon reservoirs) could offer substantial storage capacity at low cost as well as buffer capacity to meet changing seasonal electricity demands or possible disruptions in power supply. Underground geologic storage must have adequate capacity and ability to inject/extract high volumes with a reliable caprock. A thorough study is essential for a large number of site surveys to locate and fully characterize the subsurface geological storage sites both onshore and offshore. An isothermal compositional reservoir simulator was used to evaluate hydrogen storage and withdrawal from saline aquifers and depleted oil/gas reservoirs. The phase behavior, fluid properties, and petrophysical models were all calibrated against published laboratory data for density, viscosity, relative permeability, and capillary pressure for a given site. History-matched dynamic models of two CO2 injection field projects in saline aquifers and one natural gas storage in a depleted oil reservoir were considered as hypothetical hydrogen seasonal storage sites. A wide range of working gas volume/cushion gas volume ratios was observed, meaning that careful optimization is required for a successful storage project. For the aquifer cases, the range was 0.292 to 1.883 and a range of 1.045 to 4.4 was observed for the depleted hydrocarbon reservoir scenarios. For the saline aquifer cases, a higher injection rate, longer injection/withdrawal (I/W) cycles, and the use of pump wells to control the hydrogen plume spreading were all beneficial for improving the working gas/cushion gas ratio and the working gas volume. Plume control was important for storage in the oil reservoir in which changes in the well length location and orientation showed high sensitivity in the working and cushion gas volumes. Sensitivities to the initial gas saturation in the depleted gas reservoir scenarios suggested that both cushion and working gas volumes increased with the initial gas saturation while the ratio of working to cushion gas volumes decreased with the initial gas saturation. Finally, when comparing the ratios of working to cushion gas volumes, it was the highest for the depleted oil reservoir, followed by the depleted gas reservoir, and the aquifer.

Study on migration and plugging performance of polymer gel in fractured cores using nuclear magnetic resonance technology

In situ cross-linked polymer gels (ISCPGs) are widely used for conformance control and enhanced oil recovery (EOR) in heterogeneous petroleum reservoirs. However, the mechanisms behind their migration and plugging in fractured cores remain unclear. In this study, changes in the injection pressure difference before and after the treatment of HPAM/phenolic resin gel was monitored by core displacement experiment. The gel was injected with two different gelation states, i.e., gelant and pre-crosslinked gel. Meanwhile, we analyzed the nuclear magnetic resonance (NMR) T2 signal and imaging of the cores that were treated with the polymer gel system during various injection stages. Results indicated that NMR technology can effectively analyze the migration and plugging performance of polymer gels in fractured cores at a microscopic level, both before and after gelation. The gelant effectively plugged the fracture when the injection rate was low, but a great amount of the gelant entered the matrix and damaged the matrix. In contrast, it formed a plugging layer at the inlet face and also caused damage at high injection rates. For conformance treatment of pre-crosslinked gels, the gel did not easily enter the matrix. When the injection rate of pre-crosslinked gels increased, its plugging efficiency for the fractured cores enhanced. Therefore, engineers should optimize gel state, injection rate, and injection pressure according to the specific reservoir conditions before oilfield operations. This study can help researchers understand the microscopic migration and plugging mechanism of polymer gels in cores at the microscopic level. It will also help researchers to pay more attention to the NMR technique to further understand its application in petroleum reservoir conformance improvement.