Fracture Width Research Articles

PORE-SCALE ANALYSIS OF AQUEOUS PHASE TRAPPING RESISTANCE IN CARBONATE GAS RESERVOIRS

In carbonate gas reservoirs, water in aquifers can flow into reservoirs through highly permeable fractures, which leads to aqueous phase trapping and reduces well productivity. In this paper, flow resistances during aqueous phase trapping are analyzed. A mathematical model of aqueous phase trapping resistances is established at the pore scale, taking into account capillary pressure, gas viscous force, and water viscous force. The factors affecting aqueous phase trapping resistances are discussed, including pore radius, throat radius, flow velocity, fracture width, etc. Results show that gas flow resistance in the matrix easily exceeds the water flow resistance in fractures. Water in fractures occupies the flow path in the formation and traps gas inside the matrix. Consequently, aqueous phase trapping occurs. The gas flow resistance is mainly affected by the throat radius because the capillary pressure accounts for more than 98% of the gas phase flow resistance. When the throat radius increases from 0.1 μm to 10 μm, the gas flow resistance decreases by 89.99%. The water flow resistance is mainly influenced by the fracture width and the flow velocity. Water flow resistance has a linear relationship with the flow velocity. The water flow resistance is also sensitive to fracture width. When the fracture width rises from 0.2 μm to 1 μm, the water flow resistance diminishes by 96%.

Quantitative Analysis of Hydraulic Fracturing Test Site 2 Completion Designs Using Crosswell Strain Measurement

Summary The implementation of effective completion design configurations during hydraulic stimulation is critical for the economic development of unconventional reservoirs. Low-frequency distributed acoustic sensing (LF-DAS)-based crosswell strain measurement is an advanced monitoring technique used to diagnose completion design efficiency but has been primarily restricted to qualitative analysis. In this study, we apply our novel Green-function based inversion algorithm to calculate fracture geometry (i.e., width) using the Department of Energy sponsored Hydraulic Fracturing Test Site 2 (HFTS-2) data set. The adopted algorithm relies on a 3D displacement discontinuity method to construct geomechanical models inverting linear elastic strain to hydraulic fracture widths. We use the inversion algorithm to calculate dynamic fracture widths using LF-DAS data recorded at two horizontal monitoring wells with permanent optical fiber installations. The inverted fracture widths at the monitoring wells from more than 100 hydraulic fracturing stages are used to diagnose the efficiency of eight unique completion designs implemented across three fracturing wells. We develop several metrics to evaluate completion design efficiency including the evenness of fracture widths at the monitoring wells, fracture density (i.e., number of fracture hits per foot), and fracture-width-density (i.e., fracture width/stage length). We observe a significant impact on completion efficiency with varying degrees of limited entry, tapered configurations, and stage length designs. Results indicate improved hydraulic stimulation is achieved with the implementation of limited-entry designs for extended stage lengths (ESLs), but no observable trend for normal stage lengths (NSLs). Tapered configurations significantly improve efficiency for ESLs but indicate little impact on normal-length designs. Reducing the space between perforation clusters (PCs) is determined to negatively impact design performance. Additionally, our quantitative analysis describes the impact of the nearby depletion zone on completion design efficiency. The methodology developed in this study provides operators with another level of quantitative information to optimize hydraulic fracturing treatments and reduce costs associated with the development of unconventional wells.

Comparison of percutaneous distractor and arthroscopic-assisted screw fixation with open reduction and plate fixation for Sanders II calcaneal fractures treatment: A single-center retrospective cohort study

BackgroundAlthough the numerous advancements in orthopedic surgical techniques and implants witnessed in recent decades, the management of calcaneus fractures remains among the most complex challenges in the field. This study introduced a percutaneous distractor and arthroscopic-assisted screw fixation (PDA-CRSF) technique and compared its wound-related complications and clinical efficacy with open reduction and plate fixation with sinus tarsi approach (STA-ORPF) for treating Sanders II calcaneal fractures. Patients and methodsThis retrospective cohort analysis evaluated two patient cohorts with Sanders II calcaneal fractures received either STA-ORPF or PDA-CRSF using clinical indicators time to operation, operation duration, blood loss volume, hospital stay, wound healing complications, nerve damage, American Orthopedic Foot and Ankle Society (AOFAS) Ankle-Hindfoot score, Visual Analogue Scale (VAS) score, and imaging indicators Gissane's angle (GA), Böhler's angle (BA), varus angle (VA), the length, height and width of calcaneal fractures, respectively. ResultsBetween March 2019 and March 2022, 23 patients underwent PDA-CRSF and 49 under STA-ORPF. The STA-ORPF group had fewer wound complications and nerve damage compared to the PDA-CRSF group (P < 0.05). Furthermore, the PDA-CRSF group exhibited shorter time to operation, reduced operation duration, decreased blood loss volume, and shorter hospital stay (P < 0.01). Three months after surgery, patients treated with PDA-CRSF also showed better scores on AOFAS (P < 0.01) and VAS (P < 0.05). However, at the final follow-up, the difference was not statistically significant (P = 0.222; P = 0.118). Both groups regarding radiographic indices had comparable outcomes at different postoperative follow-up stages. ConclusionThe results demonstrate that PDA-CRSF effectively reduces the risk of wound complications, shortens the surgical duration, expedites the time to surgery, and enhances post-operative rehabilitation.

Numerical simulation of hydraulic fracture propagation under energy supplement conditions

After the long-term production, due to the influence of low-pressure and low-stress fields in the near-well area, the reversion and propagation of new fractures after temporary plugging is short. It is difficult for the new fracture to extend to the remaining oil enrichment areas on both sides of the primary fractures, resulting in a low increase in the bandwidth of the fracture group after repeated fracturing, which affects the reservoir utilization. In the early stage of repeated fracturing, a large amount of pre-fracturing fluid is injected to supplement the energy of the fractures and rapidly increase the pore pressure in the local range, weakening rock strength and change the pore structure. In addition, the combination of energy replenishment and reservoir stimulation, coupled reconstruction of the seepage field and stress field, promotes the effective propagation of new fractures. However, in the process of increasing formation energy, the propagation law of hydraulic fractures and natural fractures is not clear. In this paper, the model of tight sandstone reservoir in the HQ block of Ordos Basin was established with the finite element software ABAQUS, based on the effective stress principle and the theoretical method of fluid-solid coupling numerical simulation. The propagation of a single hydraulic fracture and the interaction between hydraulic fracture and natural fracture under the condition of energy increase was investigated to better guide the field operation. The results show that for every 1 MPa pressure increase in a single hydraulic fracture, the fracture length increases by 0.62 m and the maximum fracture width decreases by 0.09 mm. When the formation energy increases by 6 MPa, the time for the hydraulic fracture to reach the intersection point with the natural fracture is shortened by 10 %, and the length of the natural fracture is 2.16 times compared with the case of 3 MPa energy increase.

Microfluidics investigation of the fracture/matrix interaction mechanisms during preformed particle gel (PPG) treatment in fractured porous media

Although water injection is one of the most common methods for enhancing the recovery from oil reservoirs, its effectiveness in severely heterogeneous porous media such as fractured rocks, is debatable. Preformed Particle Gel (PPG) treatment is one of the most promising methods which is considered for water shut-off in the near wellbore area or improving the sweep efficiency of the injected water deep in the reservoir. Recognizing the PPG transport mechanisms in fracture, fracture/matrix interactions during and after PPG treatment, and the contributing parameters on such mechanisms, is a prerequisite for designing an effective water shut-off process and possible enhanced oil recovery (EOR). With this aim, the dynamic behavior of PPG samples is studied in two different fractured porous media representing the near wellbore area (dual permeability model) and deep in the reservoir zones (single permeability model). During encroachment of the gel particles in fracture, the dehydration of gel produces a large volume of filtrate which sweeps the oil inside the matrix. PPG particles might go through deformation, shrinkage and/or breakage, before infiltrating into pores of matrix where they form an impermeable cake. The experimental results shows that formation of such cake, is one of the main affecting parameters in the performance of the conformance control and EOR. Additionally, the affecting parameters such as concentration of nano-silica (n-SiO2), width of fracture, particles size, ionic strength of brine and injection rate of gel were examined. The concentration of n-SiO2 affects the gel loss factor (ratio of loss modulus to storage modulus) and hence its encroachment behavior. The gel sample with 1 wt% n-SiO2 has the highest loss factor which makes it more favorable for water shut-off considering lower injection pressure and less volume required for treatment. The water shut-off treatment is more effective in the case of systems with wider fractures. Based on the size of the PPG particles, the plugging mechanisms of the fracture can be either direct plugging, bridge plugging or a combination of both mechanisms, however all the studied samples provided same degree of plugging efficiency in the performed experiments. Swelling the samples in brines with higher salinities reduces the required volume of gel, while the injection pressure remained unaffected. To reduce the required volume of gel, highest possible injection rate is recommended, since the shear thinning rheology of the gel damps increment of injection pressure. In the case of single permeability model, water shut-off treatment reduced the fracture conductivity effectively, so that in the subsequent flooding, the injected brine was diverted toward matrix and the displaced oil was recovered through the fracture. During water flooding stage after gel placement, the withstanding pressure of PPG must be taken into account to avoid gel rupture, movement and washout.

Theoretical Simulation of the Resistivity and Fractured–Cavernous Structures of Carbonate Reservoirs

Recently, theoretical modeling based on rock physics has emerged as a pivotal approach to studying the resistivity of complex fractured–cavernous microstructures. In this work, to study the effects of fractured–cavernous structures on carbonate reservoir resistivity, electrical conductivity models were developed based on the effective medium theory and Ohm’s Law, and theoretical simulations were performed to examine how the porosity and resistivity of the rock matrix, the formation water resistivity, and the parameters of the fractured–cavernous microstructure affect the resistivity of rocks saturated with petroleum or water. Furthermore, the modeling results revealed the specific relationships between these factors in petroleum-saturated and water-saturated rocks. For vuggy reservoirs, a significant negative correlation between throat diameter and resistivity was revealed when variations in the rock matrix and formation water resistivity were negligible. Furthermore, the pore shape—especially the extension of pores in the direction of the current—severely reduced the resistivity of petroleum-saturated rocks. For fractured reservoirs, the porosity and resistivity of the rock matrix were the primary factors affecting resistivity, with the fracture inclination angle and width also exhibiting pronounced effects on the resistivity of water-saturated rocks. The rock cementation exponent was much smaller when the matrix pores were interconnected through fractures than when they were interconnected through throats. The findings reveal that the effects of the structural parameters of fractured–cavernous carbonate reservoirs on reservoir resistivity differ between petroleum-saturated and water-saturated rocks. The conventional Archie’s equation is insufficient for evaluating fluid saturation in carbonate reservoirs. A saturation evaluation model with a variable rock cementation exponent tailored to the specific reservoir type should thus be developed.

Lithium Dendrite Formation inside Li3PS4 Solid Electrolyte Observed Via Multimodal/Multiscale Operando X-Ray Computed Tomography

Sulfide-based all-solid-state batteries using a lithium metal anode are expected to be next-generation batteries due to their extremely high energy density. In order to use the lithium metal as the anode, suppressing dendrite of lithium metal during charge/discharge processes is essentially important. It has been reported that lithium dendrite formation occurs not from the lithium/sulfide solid electrolyte interface, but in the sulfide solid electrolyte, isolated from the interface1, 2. The formation of lithium dendrite within the sulfide solid electrolyte is caused by electron conduction in the sulfide solid electrolyte and at the sulfide solid electrolyte/void interface3. However, fundamental information on the mechanism of lithium dendrite formation in a sulfide solid electrolyte caused by its electron conduction is lacking. In this study, the three-dimensional morphological changes of the lithium dendrite in Li3PS4, which is a typical sulfide solid electrolyte, were observed directly using multimodal/multiscale operando computed tomography (CT) under an applied pressure.Li/Li3PS4/Li cells were constructed in a diameter of 10 mm and 1 mm for the critical current density measurements and X-ray CT measurements by using SPring-8 BL20XU respectively. X-ray CT images for behavior change with the electrochemical operation were collected in micro and nano scales at 25 °C every 30 mins. After a series of data processing steps, these images were converted to cross-sectional slices that were then stacked together to render a 3D reconstruction of the cell. The 3D imaging data coupled with precise species segmentation show that the lithium metal deposition start point is spatially separated from the lithium metal anode. The gradient in thickness of a lithium filament with repeated charging, widening the plating-susceptible region horizontally in the process and eventually led to cell failure. The lithium nucleation initiates along the pre-existing voids where local electronic conductivities are high during the plating. The deposition then widens from the nucleation across the electrolyte horizontally. Accompanied with streak fracture widening through the Li3PS4, does a Li/Li3PS4/Li cell finally short circuit. By combining the multimodal/multiscale operando X-ray computed tomography with X-ray absorption spectroscopy and electrochemical impedance spectroscopy measurements, we revealed that the electronic conduction of reductive decomposition products and the solid electrolyte/void interface cause the lithium deposition within the Li3PS4. These results suggests that the suppression of reductive decomposition and sulfide solid-state electrolytes with low electronic conductivity plays significant roles in suppressing the growth of lithium dendrites in the solid-state electrolyte layer.

Synergistic impacts of fracture–matrix system on recovery rate during spontaneous imbibition in tight sandstones

Hydraulic fracturing is considered a promising technology for enhancing the recovery rate from tight oil/gas reservoirs. However, the hydraulic fracturing process inevitably leaves a portion of the fracturing fluid in the reservoir. This causes a noticeable decrease in the recovery rate of oil/gas. Thus, the flow mechanism of fracturing fluids in fracture–matrix system remains unclear. In this study, spontaneous imbibition (SI) experiments were conducted on sandstone samples with different fracture widths. Subsequently, magnetic resonance imaging (MRI) was used to monitor the displacement of the imbibition leading edge at the fracture edges. Finally, the recovery rate was quantified using the T2 spectra of multi-scale pores during the SI process. The experimental results revealed the following: (1) A significant contribution from the pre-rapid growth stage was observed during the SI process. (2) The heterogeneity of sandstone sample resulted in a rough imbibition leading edge and a decreasing gradient in fluid saturation over time. (3) The increase of distilled water in multi-scale pores during the SI process varied, specifically a preferential increase in micropores, followed by mesopores and macropores. (4) When the sandstone sample had a wider fracture, the synergistic effect between the fracture-matrix system was significantly enhanced, and a higher recovery rate was observed.

A new numerical model for simulation of flow on rough fracture

Hydraulic fracturing is an important means to develop unconventional oil and gas. The fractures produced by hydraulic fracturing have the characteristics of a rough surface, high tortuosity, and strong randomness. The fluid migration law in rough fractures is more complicated, which leads to the change of the law of conductivity in fractures becoming more complex. Meanwhile, it is difficult to get certain regularity for the fracture surface obtained by direct fracturing. As a result, it is an arduous task to explore the influence of fracture roughness on conductivity by experimental means. Therefore, it is a feasible idea to use simulation to study the flow conductivity in rough fractures, which can be calculated by Darcy's seepage equation. In previous studies, quantitative characterization of rough fractures was rarely studied, and the three-dimensional Darcy seepage model of rough fractures was lacking too. In this paper, the rough surface profile and waveform are analyzed by analogy, and the height of the rough fracture surface, as well as the phase and wavelength of the waveform, were taken as the control parameters to generate the rough fracture surface. Then, the fractal dimension was used to characterize the roughness of the fracture surface. Coupled with the rough fracture model and the Darcy flow model, a three-dimensional Darcy flow model of rough fracture was established. Next, a new parameter, equivalent permeability, was defined to quantify and characterize the fracture permeability affected by roughness. Subsequently, the simulation results were verified by the experimental data. Finally, the effects of fracture surface fractal dimension, fracture width, proppant distribution, shear slip, and tortuous angle on the flow field were studied. This study provides a new model for the simulation of a rough fracture flow field, which provides important insight for understanding the properties of rough fracture flow fields.

Stochastic inversion for equivalent hydraulic fracture characterization using low-frequency distributed acoustic sensing data

Distributed fiber-optic sensing, a game-changing technology, has been successfully applied in monitoring hydraulic fracturing treatments. The cross-well fiber-optic strain/strain-rate responses are directly related to the fracture-propagation process and dynamic fracture geometry. Extracting the insightful information regarding hydraulic fractures requires robust interpretation workflows. In this paper, we aim to develop a stochastic inversion approach to characterize the dynamic equivalent fracture geometry and quantify the associated uncertainties using cross-well low-frequency distributed acoustic sensing (LF-DAS) measurements. A fast analytical forward solver based on the 3D displacement discontinuity method is developed to model the strain. The objective function is the sum-of-squares error between the modeled strain and the measured strain. We focus on an equivalent fracture geometry with a predefined length centered around the monitoring well, which is a reasonable assumption considering the spatial sensitivity of LF-DAS. Therefore, the model parameters reduce to fracture width and height of the equivalent fracture. We adopted the delayed rejection adaptive metropolis (DRAM) algorithm, an efficient Markov-chain Monte Carlo (MCMC)-based method, to perform the optimization. The efficiency and accuracy of the algorithm are tested using a synthetic case that has three monitoring wells at different locations. The mean values of fracture width and height are both close to the true values with negligible standard deviations for all the three monitoring wells. The algorithm performance is not sensitive to the initial guess and the predefined length needs to be large enough. Then, a field case with a single cluster from the HFTS-2 project is presented. The fracture width increases from about 0.5 mm to about 0.9 mm during the pumping stage and gradually decreases during the shut-in period. The fracture height changes during the pumping stage and stabilizes at about 150 m during the shut-in period, the trend of which is consistent with the LF-DAS signals from the offset vertical monitoring well. To the best of our knowledge, this is the first algorithm that can efficiently quantify the fracture width and height simultaneously. The results could provide novel insights on the characteristics of fracture geometry and significantly improve the understanding of complex fracture propagation processes in subsurface reservoirs.

DESIGN OF HYDRAULIC FRACTURING CARBONATE RESERVOIR USING A SIMULATOR IN THE IQ FIELD X WELL

The inability of a reservoir to pass large amounts of fluid can be caused by very low permeability. Objective: This research aims to increase well productivity in wells that have low permeability. Based on reservoir data, the permeability in the IQ well is tight permeability, namely 0.153 mD, so that fluid in the reservoir cannot flow into the well due to the low permeability of the formation. The low permeability of the formation resulted in a low production rate of 39 BLPD. Methodology and results: in this research a stimulation acidizing method was used but this method was less than optimal (seen from the absence of a pressure drop after acid was injected at a high flow rate), so a hydraulic fracturing method was carried out on the IQ well to increase well productivity. The results of this research use the PKN (Perkins, Kern &amp; Nordgren) fracturing model to obtain a fracture length greater than the fracture height. The fracturing fluid used as pad and slurry is YF120.HTD and the flush fracturing fluid used is 4% KCL Water. The proppant used is Carbolite 20/40. The resulting fracture geometry was 111 ft, fracture height 55 ft and fracture width 0.375 in. The conductivity value of the fracture formed was 18.1 mD with a fracture permeability of 320,177.383 mD/ft. The productivity index increased by 2,945 with a production rate of 440.14 BFPD. The total cash flow obtained was $4,858,624.11 and NVP $2,413,572.70. The capital issued will be returned within 21 days. Conclusion: based on the results above, the IQ well is suitable for hydraulic fracturing

Evaluation of High-Temperature Recrosslinkable Preformed Particle Gel for Fluid Loss Control during Drilling

Lost circulation has become one of the biggest challenges that drilling engineering faces during drilling, especially at high-temperature reservoirs. The consequences of lost circulation can vary from an economic aspect as well as a safety aspect. In this paper, the capability of a novel high-temperature recrosslinkable preformed particle gel (HT-RPPG) is evaluated to see whether it can be better used to control severe and total losses. The HT-RPPG is injected in the form of dispersed swellable gel particles, but it can self-crosslink to form a strong bulk gel after being placed in target zones. The sealing pressure and plugging efficiency of the HT-RPPG were evaluated utilizing a core flooding test. Various impacting factors were investigated, including the swelling ratios, fracture widths, and bentonite concentrations. Results indicated that HT-RPPG is an excellent material that can be used to control the severe loss of drilling fluids in fractured reservoirs with temperatures up to 130°C. The recrosslinked RPPG could withstand pressure up to 1,077 psi/ft for fractures up to 2 mm, and permeability was reduced more than 107 times.

Permeability reduction techniques: Plain and fiber HPAM gels in fractured cores

The aim of this study is to investigate how fibers influence the ability of polymer gels to resist washing out from fractures. For this purpose, synthetic and mineral wool fibers were integrated into polymer gels. These fiber-gels were compared to plain gels using bottle tests, viscosity measurements, and fractured core flooding experiments.The bottle tests show no effect of 13-mm-long synthetic fibers on gel strength. However, inside a constricted fracture, the polymer-synthetic fiber gel exhibited 8.4 times higher resistance to the flow of brine compared to the plain gel. This is explained by the retention of the fibers at the constriction point. In low salinity brine, mineral wool fibers allowed a substantial improvement in gel strength, while, at the same time, a reduction in the concentration of chemicals by 40% was made possible.Furthermore, with the addition of 0.6 wt.% mineral wool fibers, the viscosity of the 0.3 wt.% polymer gel increased from 560.5 to 106,920 cp. In fact, in a 1-mm-wide fracture, a gel containing 0.3 wt.% polymer and 0.6 wt.% mineral wool fiber achieved a post-flush pressure gradient that was 58 times higher than a 0.75 wt.% plain polymer gel. Unfortunately, the choice of a makeup brine with an increased salinity resulted in the deterioration of fiber-gel strength. Nonetheless, a substantial improvement of gel strength can be achieved by adding 0.6 wt.% mineral wool fibers, even if the salinity is as high as 143 g/L. Moreover, in experiments in which the permeability of the adjacent matrix was very low, 0.018 mD, a gel of 0.3 wt.% polymer and 0.6 wt.% mineral wool fiber prepared in 242.6 g/L brine, was still superior to a 0.75 wt.% plain gel prepared in low salinity brine.Experimentation with large fracture widths of 2.55 mm and 4 mm was also done to confirm gel effectiveness. For example, a gel of 0.3 wt.% polymer and 0.6 wt.% mineral wool fiber, prepared in 14 g/L brine, provided a 1.46 times higher post-flush pressure gradient in a 2.55-mm-wide fracture, as compared to that of a 0.75 wt.% plain polymer low salinity gel in a 1-mm-wide fracture. With an increase in the salinity, to 234.6 g/L, of the makeup brine used with a fiber-gel, the resistance to the flow of brine in a 2.55-mm-wide fracture became comparable to that of a plain gel in a 1-mm-wide fracture. In a 4-mm-wide fracture, a gel with 0.3 wt.% polymer prepared in 234.6 g/L brine and one of 0.5 wt.% polymer prepared in 14 g/L brine, each with 0.6 wt.% mineral wool fiber, provided maximal post-flush pressure gradients equal to 12–14 psi/ft. This is the same range usually expected from a 0.5 wt.% relatively low molecular weight plain polymer gel in a 1-mm-wide fracture.Although, fibers improved the ability of gels to resist washing out from fractures, in a 4-mm-wide fracture such a fiber-gel could not provide notable resistance to the flow of brine with an increase in the superficial flow velocity higher than 1,000 ft/d. Discovering formulas that would increase the resistance of gels to being washed out of wide fractures must continue.

Numerical Simulation of Hydraulic Fractures Breaking through Barriers in Shale Gas Reservoir in Well YS108-H3 in the Zhaotong Shale Gas Demonstration Area

Estimating the effectiveness of hydraulic fracturing in the context of the incrfease in the shale gas demand is of great significance for enhancing shale gas production, which aims to substantially reduce fossil energy consumption and CO2 emissions. The Zhaotong national shale gas demonstration zone has complex stress structures and well-developed fracture zones, and thus it is challenging to achieve targeted reservoir segment transformation. In this paper, we construct and optimize the geometry of hydraulic fractures at different pressures considering the upper and lower barriers in hydraulic fracturing simulation experiments and numerical modeling. The numerical simulation results show that the pore pressure exhibits a stepped pattern around the fracture and an elliptical pattern near the fracture tip. During the first time of injection, the pore pressure rapidly increases to 76 MPa, dropping sharply afterward, indicating that the fracture initiation pressure is 76 MPa. During the fracture propagation, the fracture length is much greater than the fracture height and width. The fracture width is larger in the middle than on the two sides, whereas the fracture height gradually decreases at the fracture tip in the longitudinal direction until it closes and is smaller near the wellbore than at the far end. The results revealed that the fracture width at the injection point reached the maximum value of 9.05 mm, and then it gradually decreased until the fracture width at the injection point dropped to 6.33 mm at the final simulation time. The fracture broke through the upper and lower barriers due to the dominance of the effect of the interlayer principal stress difference on the fracture propagation shape, causing the hydraulic fracture to break through the upper and lower barriers. The results of the physical simulation experiment revealed that after hydraulic fracturing, multiple primary fractures were generated on the side surface of the specimen. The primary fractures extended, inducing the generation of secondary fractures. After hydraulic fracturing, the width of the primary fractures on the surface of the specimen was 0.382–0.802 mm, with maximum fracture widths of 0.802 mm and 0.239 mm, representing a decrease of 70.19% in the maximum fracture width. This work yielded an important finding, i.e., the urgent need for hydraulic fracturing adaptation promotes the three-dimensional development of a gas shale play.

Durability investigation of fractured coal-gasified ash slag concrete eroded by sulfate and chlorine salts

The combined action of sulfate and chlorine salts erodes concrete structures in coastal and saline-alkali zones. The induced fractures under load also accelerate the deterioration of concrete. In this study, ion erosion tests of fractured coal-gasified ash slag (FC-GAS) concrete under dry-wet cyclic conditions were performed using ordinary concrete as the reference. The mass loss rates, the relative dynamic moduli of elasticity, and the distribution patterns of chlorine and sulfate ions of specimens in erosive environments of single sulfate salt, single chlorine salt, and mixed sulfate and chlorine salts were measured. The deterioration mechanism of FC-GAS concrete under coupled erosion by sulfate and chlorine salts was explored with SEM and XRD techniques. By introducing the influence coefficient and deterioration coefficient of the fracture width of FC-GAS concrete, a modified model describing the diffusion behavior of chlorine ions in FC-GAS concrete was established. The results show that for the concrete specimens after erosion in sulfate salt and the mixture of sulfate and chlorine salts, the mass and the relative dynamic modulus of elasticity first increased and then dropped. The deterioration of the concrete performance after soaking in the mixed solution was significantly lower than that of the specimen after dry-wet cycles in the single solution. The formation of fractures accelerated ion erosion. Chlorine and sulfate ions in the mixed solution could inhibit the diffusion of other ions. The diffraction peak strengths of the erosion products of the specimen after dry-wet cycles in the mixed solution were significantly reduced. The results calculated by the proposed modified model on the diffusion of chlorine ions in FC-GAS concrete agreed with the experimental results.

A Powerful Prediction Framework of Fracture Parameters for Hydraulic Fracturing Incorporating eXtreme Gradient Boosting and Bayesian Optimization

In the last decade, low-quality unconventional oil and gas resources have become the primary source for domestic oil and gas storage and production, and hydraulic fracturing has become a crucial method for modifying unconventional reservoirs. This paper puts forward a framework for predicting hydraulic fracture parameters. It combines eXtreme Gradient Boosting and Bayesian optimization to explore data-driven machine learning techniques in fracture simulation models. Analyzing fracture propagation through mathematical models can be both time-consuming and costly under conventional conditions. In this study, we predicted the physical parameters and three-dimensional morphology of fractures across multiple time series. The physical parameters encompass fracture width, pressure, proppant concentration, and inflow capacity. Our results demonstrate that the fusion model applied can significantly improve fracture morphology prediction accuracy, exceeding 0.95, while simultaneously reducing computation time. This method enhances standard numerical calculation techniques used for predicting hydraulic fracturing while encouraging research on the extraction of unconventional oil and gas resources.

Research on stress sensitivity of fracture-hole carbonate reservoirs under drilling fluid immersion

Fracture-hole carbonate reservoirs feature the development of multi-scale fractures and dissolution holes. Invasion of drilling fluid into the reservoir and its prolonged interaction with the rock can readily induce a variety of damages, including stress-sensitive damage, consequently diminishing the productivity of oil and gas wells. Experiments were conducted on both dry/wet fractured rock samples and dry/wet fractured rock samples containing holes to investigate the mechanism of stress sensitivity in fracture-hole rocks subjected to fluid soaking. The results indicate that: (1) During the loading process, the highest damage rate to the permeability of fractured rock samples can reach up to 95%. The stress sensitivity coefficients for fracture-hole rock samples with half-hole depths of 2.5 mm, 5.0 mm, and 7.5 mm are 0.58, 0.41, and 0.25, respectively. The permeability damage rate of fracture-hole rock samples soaked with fluid is approximately 80%. (2) As the depth of the hole increases, the stress sensitivity coefficient decreases. The hole's depth is inversely proportional to the maximum stress, while being directly proportional to the maximum displacement of the rock sample. (3) Upon fluid soaking, pressure dissolution occurs within the fractured rock samples, shrinking the fracture width by 15.71–26.17%. (4) Following a 48-h immersion of the rock samples in an alkali solution, decalcification occurs and the pore structure is compromised, thus amplifying the degree of stress sensitivity.

Permeability enhancement and coal fines removal through oxidation treatment in coalbed methane reservoirs

This study utilized anthracite coal samples from Zhijin Block and applied NaClO as the oxidant to investigate the effects of oxidation treatment on permeability enhancement and coal fines migration. Subsequent to oxidation treatment, the coal samples demonstrated an average increase of 42.17% in the equivalent hydraulic aperture (EHA). This treatment also resulted in the expansion of fluid flow channels, contributing to an average permeability enhancement of 108.85% in the coal samples. Resulting from the non-uniform dissolution of the oxidant on the fracture surface of coal, self-propping fractures were formed, effectively maintaining the conductivity of fractures. The oxidation treatment converted the wettability of fracture surface from hydrophilic to hydrophobic. This transformation proved advantageous for the dewatering process within the fractures. Moreover, even under high confining stress, the 5 wt% NaClO solution still exhibited a favorable permeability enhancement effect on coal. The oxidation treatment resulted in a particle size degradation rate of 40.38%. Considering the properties and particle size distribution characteristics of both the coal fracture surface and coal fines, the affirmative impact of oxidation treatment on coal fines removal was analyzed based on the extended DLVO theory. The calculated results showed that the adhesion force between coal fines and fracture surface was weakened. Coupled with the effect of fracture widening, the outcome was a notable 26.99% increase in the quantity of coal fines that migrated with the fluid under the drag force after oxidation treatment. The research results presented in this paper provide another option for enhancing permeability of coalbed methane reservoirs, which has important reference significance for the broader economic development of such reservoirs.

Experimental Study on Seawater Intrusion Law and Countermeasures within Island Underground Water-Sealed Oil Storage Caverns

Underground water-sealed oil storage caverns constructed in island environments is a promising approach for expanding oil storage caverns. However, few researchers have studied the risks of seawater intrusion and the distribution characteristics of intrusion interfaces in large underground water-sealed oil storage caverns in island environments. In this paper, we established a visualized physical simulation platform to investigate the characteristics and control measures of seawater intrusion in single fracture of rock masses within island underground water-sealed oil storage caverns. In addition, the effects of the excavation of caverns, the distance between the cavern and coast, fracture width, seawater level, oil storage stage, water curtain, and water injection pressure were evaluated. The results show that excavation of oil storage caverns carries the risk of seawater intrusion. Specifically, reducing the distance between the oil storage caverns and the coast, increasing the fracture width, and raising the seawater level all contribute to accelerated seawater intrusion into the caverns. However, the vertical water curtain can effectively inhibit seawater intrusion, and increasing the injection pressure of vertical water curtain can avoid the risk of seawater intrusion into the caverns. The research results provide an experimental basis for the study of seawater intrusion in underground oil storage caverns in island environments.

Effect of Non-Uniform Minerals Distribution on Hydraulic Fracture Evolution during Unconventional Geoenergy Exploration

To study the effect of the non-uniform distribution of minerals on the development of microcracks within the rock during hydraulic fracturing, a novel numerical model considering multiple random mineral distributions was designed. The model investigated the impacts of mineral grain size, composition, and spatial arrangement on fracture initiation and propagation. The results indicate that the presence of the hard-phase mineral quartz can alter the propagation path of fractures, and increase the width of hydraulic fractures. In coarse-grained granite, the range of crack deflection is maximized, while in medium-grained granite, it is more prone to forming convoluted elongated cracks. A higher quartz content in granite further contributes to the formation of complex crack networks. Simultaneously, the evolution of granite fractures and variations in breakdown pressure in heterogeneous granite were investigated, considering the influence of core parameters such as fluid injection rate, fracturing fluid viscosity, and horizontal stress difference. The research reveals that a high injection rate promotes straight-line fracture expansion. Moreover, modest fluctuations in fracturing fluid viscosity have minimal effects on fracture morphology. When the fracture development avoids quartz, under the influence of high horizontal stress differential, it clearly turns toward the direction of the maximum principal stress. This study can offer insights into innovative and optimized deep reservoir fracturing techniques.