Injection Pressure Curves Research Articles

Fracture propagation characteristics of layered shale oil reservoirs with dense laminas under cyclic pressure shock fracturing

Forming a fracture network through fracturing stimulation is significant to efficiently developing shale oil resources. However, the complex lithological characteristics and dense laminas of continental shale oil strongly shield fracture propagation. The concept of "cyclic fluid injection induces rock fatigue" was introduced into shale oil fracturing technology, and the cyclic pressure shock fracturing method was designed. The horizontal well fracturing simulation experiments used prepared shale rock samples from the Permian Lucaogou Formation shale oil reservoir outcrop in Jimusar Sag, Junggar Basin. Two pressurization states were obtained through constant injection and rapid release of accumulated high pressure, corresponding to conventional and pressure shock conditions. The characteristics of fracture propagation under different fracturing methods were analyzed by combining acoustic emission monitoring and injection pressure curve response. Research has found that the dense laminas with a certain original width near the wellbore significantly inhibit the vertical propagation of hydraulic fractures (HFs), and conventional constant-rate fracturing methods make it difficult to stimulate the reservoir effectively. Fatigue fracturing can increase the complexity of near-wellbore fractures, but the HFs still tend to be arrested by the laminas. The bottom hole pressure (BHP) is artificially increased to a value far exceeding the rock breakdown pressure near the wellbore by applying the cyclic pressure shock fracturing method. It can avoid the communication between micro-cracks and horizontal laminas during the BHP constant rate increase process and overcome the inhibition of weak layers on vertical propagation. Besides, the fracture height and number of activated laminas positively correlate with the number of cycles. When the shock pressure is about 30 MPa, the fracture height of the three cycles increases by 50% compared to a single shock. In addition, the shock pressure has a more significant effect on the fracture height, and the fracture height increases significantly with the increase of shock pressure. The shock pressure increased by about 57%, and the fracture height increased by 60%. High-pressure shock has a certain effect on the naturally weak surface of the far well, which may cause the slip of the weak surface to produce AE signals. This provides a new approach for improving fracture complexity and control volume in layered shale oil reservoirs with dense laminas.

Experimental investigation of the impacts of supercritical carbon dioxide on acid-etching fracture morphology and conductivity in tight carbonate reservoir

Carbon dioxide (CO2) as energized fluid has been used for acid-fracturing in tight carbonate reservoir. CO2 is often pumped into the wellbore in liquid phase with acid systems, and transited into supercritical state under the high-temperature formation. While the effect of supercritical CO2 (SC-CO2) on acid-etched fracture morphology and conductivity have rarely been investigated. The acid-etching and conductivity experiments were conducted on the outcrops of the Ma5 sub-member of the Ordo Basin in China. The mixed phase reaction simulation device was developed firstly. These experiments involved the mixing of SC-CO2 with various fluids, including formation water and viscoelastic surfactant (VES) acid, as well as different SC-CO2 concentrations with VES acid. The results show that 100 % SC-CO2 is easy to activate natural fractures without dissolution. After 20%SC-CO2 mixed with formation water, the dissolution ability of the mixed solution and conductivity is only 11.8 % and 1 ∼ 2 % of VES acid respectively. Roughness of the morphology created by the mixture of SC-CO2 with VES acid, exhibits a reduction compared to VES acid-etching, accompanied by the presence of wormholes. Additionally, there is a decrease in conductivity and increase in its retention rate. With the increase of SC-CO2 concentration, the roughness of acid-etching fracture decrease and the injection pressure curve becomes more stable. While the reaction rate is also retarded nearly linearly as the SC-CO2 concentration increases. Especially, when the SC-CO2 concentration is up to 40 %, the acid-rock reaction rate reaches only 55 % of that of VES acid. The conductivity of mixed-acid-etched fracture exhibits a segmented characteristic. During the low-medium closure pressure stage, the acid-etched fracture by VES acid generates high conductivity, specifically when it is below 34.5 MPa. While the higher the SC-CO2 concentration in the mixed acid is, the greater the conductivity and retention rate are at pressures above 34.5 MPa during high closure pressure stage. The conductivity of SC-CO2 acid-fracturing fracture depends on the non-uniform etching of the acid solution. The increase in SC-CO2 concentration of the mixed acid not only enhances conductivity and retention rate under high closure pressure, but also reduces the acid volume required for acid-fracturing.

Parameter identification of minifrac numerical tests using a gradient boosting‐based proxy model and genetic algorithm

AbstractIn recent years, the petroleum industry has devoted considerable attention to studying fluid flow inside fracture channels due to the discovery of naturally fractured reservoirs. The behavior prediction of these reservoirs is a well‐known challenging task, in which the initial stage consists of identifying reservoir hydromechanical parameters. This work proposes an artificial intelligence‐based approach to identify hydromechanical parameters from borehole injection pressure curves acquired through minifrac tests. This approach combines proxy modeling with a stochastic optimization algorithm to match observed and predicted borehole pressure curves. Therefore, a gradient boosting‐based proxy model is built to predict borehole pressure curves, considering a proper strategy to develop time series modeling. Moreover, a Bayesian optimization algorithm is applied to compute the gradient boosting hyperparameters. In this optimization scenario, this paper proposes an appropriate objective function established from the assumed time series prediction strategy and the k‐fold cross‐validation. Finally, a genetic algorithm is adopted to identify unknown hydromechanical parameters, solving an inverse problem. Based on the proposed workflow, a study of the importance of the hydromechanical parameters is developed. To assess the methodology applicability, the approach is employed to identify parameters in synthetic and field minifrac tests. The results present how this approach can adequately identify hydromechanical parameters of hydraulic fracturing problems.

Study on observation method of injection pressure curve in high pressure common rail system

The performance of the diesel engine was determined by the injection pressure of the high pressure common rail system. The observation method of the injection pressure curve was of great value in evaluating the operating conditions of the diesel engine. However, the observation method could make it impossible to directly observe the injection pressure data on a high pressure common rail system in operation. In this paper, common rail pressure signals and control pulse widths, which were easy to collect, were used as the basis for proposing a GRU (Gated Recurrent Unit) based model for the observation of injection pressure curves of high pressure common rail system in order to solve the above problem. The accuracy and precision of the model was verified by the experiments and compared with commonly used simulation models. From the results, it was concluded that the overall accuracy of the injection pressure curve observation was similar to that of the simulation model, but the accuracy was higher around the peak of the injection pressure, as well as the equipment requirement was low and the calculation speed was fast. The mean EMD of the curvilinear observation model of injection pressure of high pressure common rail system is similar to that of the 1D simulation model, with 37.88 and 33.62 respectively. The overall difference in injection pressure between the two models is similar with 53.62 and 54.23 MPa respectively. On the same computing platform, the average computation time of the test set containing five states is 0.0113 s, and the simulation time of each running state is 12951.6 s using AMESim software.

Experimental study on the multiple fracture simultaneous propagation during extremely limited-entry fracturing

Horizontal well with multi-stage fracturing is one of the most effective stimulation methods for unconventional reservoirs, e.g. tight oil/gas or shale. To maximize reservoir stimulation volume (SRV), tighter fracture spacing and fewer perforations are distributed in one stage during extreme limited-entry fracturing (XLEF) in recent years. However, the fracture geometries and injection pressure curve are not clear when multiple fractures with close spacing were created simultaneously in the perforated wellbore during XLEF. This study investigated the multiple fracture simultaneous propagation in the XLEF perforated wellbore based on the true tri-axial fracturing experiments. Critical factors of horizontal stress difference (HSD), the number of perforation clusters, helical/in-plane perforated method, number of perforations per cluster and fracturing fluid flowrate were investigated in detail. The results showed that, firstly, compared to one fracture produced by the helical perforated method, XLEF with the in-plane perforated method has a higher breakdown pressure and could simultaneously create multiple transverse fractures. Secondly, longitudinal fractures and a small number of curved transverse fractures occurred simultaneously under lower HSD conditions, while multiple parallel transverse fractures could be created under high HSD conditions. Thirdly, increasing the number of perforations per cluster will reduce perforation cluster effectiveness, and increasing the number of clusters will lead to the merging of multiple fractures. Finally, three relationships between pressure response and fracture geometries during XLEF, e.g. single transverse fracture, multiple transverse fractures, co-existence of longitudinal and transverse fractures, have been revealed. This study provides a meaningful perspective for the multiple fracture propagation in the perforated wellbore, which could help the field fracturing design during XLEF.

Numerical Simulation of Fracture Propagation during Refracturing

Hydraulic fracturing is repeated in some unconventional wells after production since the initial fracturing treatment. Due to prior production, the stress field around the existing fractures possibly rotates, and this impacts the refracturing operation. In this study, an extended finite element model (XFEM) including junction enrichments of intersecting fractures was proposed to simulate fracture propagation during refracturing in the cemented fractured reservoirs. In the XFEM model, a lubrication equation coupling both tangential and normal flow in hydraulic fractures (HFs) was used to describe the fluid flow behavior within the fractured elements, and the Newton-Raphson method was used to solve the nonlinear fluid–solid coupling system of the refracturing model. The effects of approaching angle, stress anisotropy, and production time were discussed. The results showed that the effects of these factors on improvement of fracture complexity during refracturing depend on the reservoir parameters and the stress field. The characteristics of the injection pressure curves during refracturing were analyzed.

Inverse analysis of hydraulic fracturing tests based on artificial intelligence techniques

AbstractIn the last decades, the study of fluid flow through discontinuities such as fractures has received significant attention from the petroleum industry owing to the discovery of naturally fractured reservoirs. Predicting the behavior of this type of reservoir is challenging and includes, as a crucial step, determining its geomechanical parameters. Several in situ tests and empirical relationships have been established to estimate these parameters. Nevertheless, these procedures have important limitations. This work proposes an artificial intelligence‐based methodology to identify geomechanical parameters from borehole injection pressure curves obtained during hydraulic fracturing tests. This methodology applies a genetic algorithm to minimize the sum of squared differences between the observed and predicted borehole pressure curves. Furthermore, an artificial neural network is adopted to build a proxy model that substitutes hydraulic fracturing numerical simulations, substantially reducing computational time. A proper recursive strategy is adopted to predict the borehole pressure curves. Additionally, a hyperparameter tuning technique selects appropriate neural network hyperparameters based on the multistep‐ahead prediction error. Finally, the framework is applied in a KGD problem that models hydraulic fracture propagation. The benchmark confirms the capability of the proposed methodology to identify geomechanical parameters from fracturing tests.

Multi-fracture initiation sequence and breakdown pressure in horizontal wells during TDPF: A visualization experimental investigation based on PMMA

Temporary plugging and diverting fracturing (TDPF) is an effective stimulation method to achieve multiple uniform fracture propagation in unconventional reservoirs. The plugging mechanism of diverters and the feasibility of diverted fractures have been investigated well in previous studies. However, few studies aim at the relationship between the multi-fracture morphology and injection pressure curve during TDPF because multiple fractures can not be directly observed during the fracturing process. This study established a visual true tri-axial fracturing physical experiment based on transparent polymethyl methacrylate (PMMA) to investigate the multi-fracture initiation sequence and breakdown pressure in the horizontal wellbore during TDPF. The critical fracture parameters, including completion method, injection flow rate, injection fluid type, fracture density, perforation depth and stress difference coefficient, were analyzed in detail based on twelve PMMA samples. The results showed that all experiments just produced one hydraulic fracture in the initial fracturing stage, but sequentially created multiple fractures after multiple diversion stages. Meanwhile, due to the effect of stress shadow, the break-down pressure of the first and second diverted fracture was 1.36 times and 1.67 times of the initial fracture respectively. In addition to the transverse fractures produced in the diversion stages, longitudinal fractures were also created along the horizontal wellbore, which decreased the multiple fracture initiation effectiveness. Optimized parameters, i.e. perforation completion method, high injection flowrate, moderate fracture density, uniform perforation depth and high-viscosity carrier fluid with diverters, were recommended to obtain more transverse fractures during TPDF. In addition, our results also revealed three fracture initiation sequences of multiple fractures in the horizontal well during TPDF. This study described the relationship between the visual multi-fracture geometries and breakdown pressure in horizontal wells during TPDF, which provides new insights into the propagation mechanism of multiple fractures and guidance for fracturing design in the oilfield.

Effect of temporary plugging agent concentration and fracturing fluid infiltration on initiation and propagation of hydraulic fractures in analogue tight sandstones

Temporary plugging agent (TP) fracturing has been widely used in many cases as an efficient technology to improve well production performance. In particular, the initiation and propagation of hydraulic fractures are vital to the evaluation of fracturing effect. Hence, the research of its influencing factors and laws is crucial for successful design of fracturing operation. As a productive research method, TP fracturing laboratory experiments have been broadly applied by innumerable scientists. Despite of the great achievements, those experiments mainly focus on the plugging ability of TP in unconsolidated and high permeability reservoirs in order to promote initiation and refracturing. However, studies are limited in light of tight low permeability reservoirs, in which TP not only function in plugging but also achieves changing the induced stress field. Especially for tight sandstone reservoirs, TP concentration and fracturing fluid infiltration are key factors affecting the initiation and propagation of hydraulic fractures of tight sandstones, and the laws have not been fully mastered. In this work, we poured artificial analogue rock samples (AARS) according to physical and mechanical parameters of tight sandstone reservoir in Shengli Oilfield, China. And true triaxial TP fracturing experiments under different TP concentrations were carried out on AARS. Aided by nano-organoboron crosslinking agent (NBC) and sleeves, different fracturing fluid infiltrations were achieved with the acoustic emission (AE) system monitoring the initiation and propagation of hydraulic fractures. In addition, the injection pressure curves, the geometries, forms and propagation process of hydraulic fractures were investigated in detail. The results show that: TP accretion, fracturing fluid infiltration and hydraulic fractures generation can produce innumerable AE energy that matches with the fluctuating injection pressure. TP fracturing leads to extension pressure higher than initiation pressure and slow down fracturing rate at relatively low TP concentration. TP concentration is positively correlated with both initiation pressure and average pressurization rate, but negatively correlated with the time for initiation, and such regularity is better reflected in weaker infiltration. 1.2% is the optimal TP concentration to increase initiation pressure and shorten the time for initiation. On the middle cross section of AARS, single-wing fractures, bi-wing fractures and multiple fractures are formed. Inside AARS, the main and branch fractures are formed. The synergy of TP, NBC and sleeves generates a complex fracture system composed of main fractures and branch ones, which reduces the influence of sand on fracture propagation. In short, properly weakening fracturing fluid infiltration by using NBC and sleeves, combined with a reasonable selection of TP concentration, have proved to be a productive way of improving hydraulic fracturing effect of tight sandstone. The findings contribute to a more comprehensive understanding of the initiation and propagation laws of hydraulic fractures of tight sandstone and conduce to the optimization of fracturing parameters. • We carried out temporary plugging agent fracturing experiments on artificial analogue rock samples of tight sandstone. • We monitored initiation and propagation of hydraulic fractures with acoustic emission system. • Temporary plugging agent concentration and fracturing fluid infiltration affects initiation and propagation of hydraulic fractures. • We put forward a productive way of improving hydraulic fracturing effect of tight sandstone.

Physical simulation test of multi-stage staged fracturing for shale horizontal wells

In order to clarify the influence of in-situ stress difference, displacement and fracturing series on the propagation of staged fractures in shale horizontal wells, we do the research based on a true triaxial hydraulic fracturing test system, using outcrop shale samples (300 mm × 300 mm × 300 mm) as the research object, combined with the new method of fracture-induced stress detection of staged fracturing and the three-dimensional morphological structure of specimens after hydraulic fracturing test. On the condition of maximum horizontal stress > vertical stress > minimum horizontal stress, we carry out the page multi-stage fracturing test study of horizontal wells in rock outcrops, to explore the influence of in-situ stress difference, pumping displacement and fracturing series on the fracture propagation of staged multi-stage fracturing in shale horizontal wells. The research results show that: because the overburden stress is lower than the maximum horizontal principal stress, the horizontal stress difference (the value is equal to the maximum horizontal stress minus the minimum horizontal stress) remains unchanged, and the reduction of the overburden stress easily leads to the opening of the bedding joints; the greater the horizontal stress difference is, the farther the propagation distance of the cross-cutting wellbore hydraulic fracture is; the net pressure is low under small displacement, the fracturing fluid is easy to filter out, and it is not easy to produce deep-penetrating main fractures; the interference between fractures with fewer fracturing stages is weak and can open hydraulic fractures of the corresponding series; the state of in-situ stress affects the compaction of bedding fractures and rock samples. When the overlying stress is low, the fracturing fluid is easy to penetrate into the bedding fractures, and the induced stress value is small and fluctuates greatly. Combined with the pump injection pressure curve and the induced stress curve, we can more accurately undersand the process of hydraulic fracturing fracture propagation. The research results of this article can promote the in-depth study of the fracture propagation law of multi-stage staged fracturing in horizontal wells.

Characteristics of Acoustic Emission Waveforms Induced by Hydraulic Fracturing of Coal under True Triaxial Stress in a Laboratory-Scale Experiment

Hydraulic fracturing (HF) is an effective technology to prevent and control coal dynamic disaster. The process of coal hydraulic fracturing (HF) induces a large number of microseismic/acoustic emission (MS/AE) waveforms. Understanding the characteristic of AE waveforms’ parameters is essential for evaluating the fracturing effect and optimizing the HF strategy in coal formation. In this study, laboratory hydraulic fracturing under true triaxial stress was performed on a cubic coal sample combined with AE monitoring. The injection pressure curve and temporal variation of AE waveforms’ parameters in different stages were analyzed in detail. The experimental results show that the characteristics of the AE waveforms’ parameters well reflect the HF growth behavior in coal. The majority of AE waveforms’ dominant frequency is distributed between 145 and 160 kHz during HF. The sharp decrease of the injection pressure curve and the sharp increase of the AE waveforms’ amplitude show that the fracture already runs through the coal sample during the initial fracture stage. The “trapezoidal” rise pattern of cumulative energy and most AE waveforms with low amplitude may indicate the stage of liquid storage space expansion. The largest proportion of AE waveforms’ energy and higher overall level of AE waveforms’ amplitude occur during the secondary fracture stage, which indicates the most severe degree of coal fracture and complex activity of internal fracture. The phenomenon shows the difference in fracture mechanism between the initial and secondary fracture stage. We propose a window-number index of AE waveforms for better response to hydraulic fracture, which can improve the accuracy of the HF process division.

Hydrofracture plugging mechanisms and evaluation methods during temporary plugging and diverting fracturing

AbstractTemporary plugging and diverting fracturing (TPDF) technique shows great advantages in stimulating unconventional oil and gas reserves. Revealing the fracture plugging mechanism and establishing the evaluation method are beneficial for revealing the mechanism of forming multiple fractures during TPDF. This work revealed the processes of plugging the fractures based on the typical injection pressure curve of hydraulic fracturing operation and then applied the stress cage model, the fracture closure stress model, and the fracture propagation resistance model to reveal the fracture plugging mechanisms. Moreover, this paper establishes a 2D XFEM model to evaluate the fracture plugging effect, and the reliability of the model is verified against the finite element model. Based on the XFEM model, this work investigates the fracture plugging effects influenced by the uneven distribution of net pressure within the fracture. The results prove that fracture mouth plugging of TPF mainly enhances the wellbore circumferential stress, in‐fracture plugging mainly enhances fracture closure pressure, fracture tip plugging mainly hinders fracturing fluids flowing toward fracture tips, all of them aim at enhancing the reopen pressure of the existing fractures and prevent the propagation of the existing fracture. Diverter bridging and plugging can change the distribution of fracture net pressure and dramatically reduce the fracture tip stress factor, and thus, the existing fracture propagation can be efficiently stopped.

Feasibility of Gas Injection Efficiency for Low-Permeability Sandstone Reservoir in Western Siberia: Experiments and Numerical Simulation

Gas injection is one of the prospective methods in the development of unconventional oil reserves. Before implementation in the field, it is necessary to justify the effectiveness of using gas agents in specific object conditions. Experiments of oil displacement on physical models with subsequent numerical modeling can provide the information necessary to justify the feasibility of using gas injection in specific reservoir conditions. This work is devoted to a series of experiments determining the minimum miscibility pressure (MMP) on a slim tube model and the analysis of oil displacement dynamics for various gas compositions, as well as numerical modeling. Displacement experiments were carried out using a recombined oil sample from one of the fields in Western Siberia. The MMP was determined by the classical method of inflection point on the displacement efficiency versus injection pressure curve, which was 34.6 MPa for associated petroleum gas (APG) and 49.9 MPa for methane. The dysnamics of oil displacement for different gas compositions at the same injection pressure showed that APG and carbon dioxide (CO2) are the most effective in the conditions of the studied field. The influence of the gas composition on the gas breakthrough point was also shown. It is revealed that the change in the concentration of the displacing agent in the outgoing separation gas helps define in more detail the process of displacement and the processes implemented in this case for various displacing gas agents. Similarly, it is shown that the displacing efficiency of a gas agent in a miscibility injection mode is affected by the configuration of wells when it is necessary to achieve MMP in reservoir conditions. For the immiscible gas injection mode, no influence of the well configuration was observed.

A FRACTAL PERSPECTIVE ON FRACTURE INITIATION AND PROPAGATION OF RESERVOIR ROCKS UNDER WATER AND NITROGEN FRACTURING

This paper mainly investigated the fractal characteristics of crack propagation in hydraulic fracturing and the effect of fractal dimension of induced fractures on the rock breakdown pressure. A series of fracturing experiments with water and nitrogen (N[Formula: see text] as the fracturing fluids were conducted on coal, red sandstone and shale. The injection pressure curves, rock breakdown pressure and macro- and micro-morphologies of the induced fractures were analyzed. A new fractal crack initiation criterion was developed to evaluate the rock breakdown pressure in hydraulic fracturing. The validity of the new criterion was verified by comparing the theoretical and experimental rock breakdown pressures. Further, the difference between the water fracturing and N2 fracturing was analyzed and the influence of crack fractal effect on the rock breakdown pressure was discussed by considering different initial permeabilities of rocks, injection rates and viscosities of fracturing fluids. The results show: (1) N2 fracturing may reduce the rock breakdown pressure and induce more tortuous macro-fractures with larger fractal dimension; (2) ignoring the actual fractal dimension of induced fractures would cause the prediction values of the rock breakdown pressure to be larger; and (3) the influence degree of crack fractal dimension on the rock breakdown pressure is related to the initial permeability of rocks, injection rate and viscosity of fracturing fluids. Therefore, we suggest the crack fractal dimension is an important factor that should not be ignored in designing the fracturing operations.

Effect of thermal shock on laboratory hydraulic fracturing in Laizhou granite: An experimental study

This paper aims to investigate the effect of thermal shock on hydraulic fracturing in hot dry rock (HDR). To simulate the thermal shock effect caused during the injection of cold water, several natural granite specimens were slowly heated to various target temperatures and then rapidly cooled down by flowing water. Laboratory hydraulic fracturing experiments were performed on granite specimens under triaxial stress condition and room temperature. After that, computed tomography (CT) scanning technique, scanning electron microscope (SEM) observation, and surface profile scanning (SPS) tests were combined to analyze the influence of thermal shock on fracture morphology from micro-scale to macro-scale. Moreover, the characteristics of injection pressure curve were discussed. Experimental results show that a single main hydraulic fracture with large aperture is created and approximately propagates along the direction perpendicular to the minimum principal stress before 300 °C. When the thermal treatment temperature is higher than 300 °C, multiple hydraulic fractures with branches tend to be created due to the existence of thermally-induced damage zone near the well hole. Experimental results of SPS tests indicate that the maximum height difference of the hydraulic fracture surface increases with increasing thermal treatment temperature. The tortuosity of hydraulic fracture significantly increases when the thermal treatment temperature is higher than 300 °C. Additionally, the analysis of injection pressure response shows that apparent non-linear pressurization, and decrease in pressurization rate and breakdown pressure are observed after 300 °C.

Deformable Microgel for Enhanced Oil Recovery in High-Temperature and Ultrahigh-Salinity Reservoirs: How to Design the Particle Size of Microgel to Achieve Its Optimal Match with Pore Throat of Porous Media

Summary Conformance control treatment in high-temperature and ultrahigh-salinity reservoirs for easing water/gas channeling through high-permeability zones has been a great challenge. In this work, we propose a deformable microgel that can be used at more than 373.15 K and ultrahigh-salinity conditions (total dissolved solids > 200 kg/m3, Ca2+ + Mg2+ > 10 kg/m3) and present a method for choosing the suitable particle size of the microgel to achieve an optimal match with the pore throat of the core. First, the particle size distribution of the microgel was analyzed to decide d50, d10, and d90 (diameter when cumulative frequency is 50, 10, and 90%, respectively). Coreflooding experiments were conducted under different permeability conditions from 20 to 900 md to investigate the migration and plugging patterns of the microgel by analyzing and fitting injection pressure curves together with the change in the morphology of the produced microgel analyzed by a microscope. The migration and plugging patterns were divided into three patterns: complete plugging; plugging—passing through in a deformation or broken state—deep migration; and inefficient plugging—smoothly passing through—stable flow. The second pattern can be further divided into three subpatterns as strong plugging, general plugging, and weak plugging. Finally, on the basis of five patterns, we build a quantitative matching relation between the particle size distribution of microgel and the pore-throat size of cores by defining three matching coefficients α = d10/d, β = d50/d, γ = d90/d (d is the average pore-throat diameter). The effectiveness of this quantitative matching relation was verified by evaluating the plugging ability (residual resistance factor) in a post-waterflooding process after the injection of 1.5 pore volume (PV) of microgel. For a strong permeability heterogeneity, the strong plugging is believed to be the expected pattern. The particles size and the pore-throat size should meet the following relationship: 1 < α < 2, 2 < β < 4, 4 < γ < 6. In this scenario, the deformable microgel particles could achieve both an effective plugging and a deep migration. The quantitative matching relation with multiple matching coefficients determined based on the particle size distribution might help to choose suitable particles more precisely in comparison to the method based on one matching coefficient (mostly, the ratio of the average diameter of particles to the average pore-throat diameter). In addition, the method itself to build a quantitative matching relation according to particle size distribution can be used for designing different particle-type conformance control agents for profile control and water shutoff treatment in field applications.

Injection pressure monitoring during peripheral nerve blocks: from bench to operating theatre

BackgroundNerve damage can occur after ultrasound-guided peripheral nerve block (PNB). Injection pressure monitoring could improve the safety of PNB. The aim was to analyse parameters affecting pressure measurements during PNB. MethodsThe flow characteristics of needles connected to a pressure-sensing device were evaluated. Needles were placed under ultrasound guidance extra or epineurally in nerves/plexus of fresh cadavers. Using three flow rates, 4 mL of saline was injected and plateau pressure was measured. Finally, orthopaedic surgery patients receiving PNB were enrolled for an observational real-time pressure monitoring study. During PNB, periods with pressure > 50 mmHg were noted (high pressure ≥ 750 mmHg). A blinded investigator recorded injection pressure curves and peak pressure. ResultsThe needle diameter influenced the injection pressure (β = 66.8; P < 0.0001). Non-echogenic needles increased the injection pressure (β = 82; P = 0.0009) compared with echogenic needles. Cadaver injection pressure was higher for intraneural (255 [122.5–555] mmHg) versus extraneural needle tip location (90 [50–158] mmHg; P < 0001); for high flow (9.6 mL/min; 470 [265; 900] mmHg) versus low flow (1.2 mL/min; 120 [71–250] mmHg) (P < 0.001) and for cervical roots (900 mmHg, intraneurally) compared with nerves (300 mmHg, intraneurally). In 37 patients and 61 procedures, there were 7 [1–18] peaks of injection pressure per procedure. Pressure was noted > 750 mmHg during 13.80% of the procedural time. ConclusionsNeedle diameter, needle tip location, type of nerve/plexus, flow rates, and the anaesthetist can have a significant effect on injection pressure values and monitoring.Trial registration: ClinicalTrials.gov ID: NCT03430453

Real-time continuous monitoring of injection pressure during peripheral nerve blocks in fresh cadavers

BackgroundThe incidence of unintentional intraneural injection while performing peripheral nerve block has been estimated to be 15% under real-time ultrasound guidance. Injection pressure increase may detect an intraneural injection. Real-time injection pressure changes throughout an entire nerve block procedure in relationship with needle tip location have never been reported. MethodsA new method was developed to precisely monitor the injection pressure curve during nerve blocks, based on a miniaturised Fabbri-Perrot pressure sensor. We tested in three fresh cadavers the ability of continuous pressure monitoring to discriminate between different tissues, as the injection pressure curve ascending slope, shape and plateau pressure value depend on tissue compliance. Injections of saline were performed by an electronic syringe pump with three different constant flow rates. Pressure was measured simultaneously at the tip and in the tubing of the needle. ResultsAt 10 mL/min injection flow, median peak injection pressure in the intraneural group at the needle tip was 315 mmHg, while at the perineural location it was 100 mmHg (p < 0.05). Median injection pressure was 95 mmHg in the intramuscular locations group, and 819 mmHg when a muscular fascia was indented (p < 0.05). A significant difference was noted for pressure measurements between the proximal port of the needle and the tip, 625 and 417 respectively. ConclusionsBased on significant differences in injection pressure values and curve shapes, the system was able to discriminate between four needle tip locations. This may help with needle tracking while performing a peripheral nerve block.

Experimental investigation of shear slippage behavior in naturally fractured carbonate reservoirs using X-ray CT

Shear slippage plays a critical role in forming complex fracture networks in unconventional reservoirs. Here we demonstrate experimentally the characteristics of slippage-induced fractures in 3D, which were not often clearly illustrated but certainly important for a better understanding of hydraulic fracture branching behaviors. The experimental characterization of slippage is realized following the design concept that most unpropped tensile fractures will close due to high confining pressure, while shear-failure fractures remain open because of unmatched rough surfaces generated during slipping, which can be detected using the CT-scan technique. In this study, the spatial distribution of natural fractures (NFs) in carbonate rock samples before fracturing are determined using X-ray computerized tomography (CT) and numerical reconstruction method. The NF angle between horizontal plane and NF plane ranges from 15° to 90°. Different hydraulic fracturing scenarios are designed and injection pressure curves show that the breakdown pressure of carbonate reservoirs can reach 20 MPa, even as high as 50 MPa under the confining pressure that vertical stress is 16.1 MPa, maximum horizontal stress is 7.5 MPa and minimum horizontal stress is 5.0 MPa. The 3D characterization of fracture distribution indicates four types of facture behaviors, namely: creation of new fractures, propagation of pre-existing fractures, connection of multiple fractures and closure of original fractures. Quantitative analyses of fracture length at different CT-scan slices demonstrate that most of the NFs are activated during testing, while limited numbers of fractures are squeezed closed under confining pressure. Finally analytical evaluation for the degree of shear slippage is performed and shows results consistent with lab experiments.

Hydraulic fracturing in high-temperature granite characterized by acoustic emission

Given the limited successes of hydraulic fracturing in enhanced geothermal systems (EGS), understanding of the hydraulic fracturing characteristics in high-temperature granites remains challenging and crucial. In this study, four groups of cube granite specimens (dimensions: 300/300/300mm) were tested to investigate the characteristics of the hydraulic fracture, for two confining pressures (0.1/0.1/0.1MPa and 10/25/30MPa) and temperatures (20°C and 120°C). Acoustic emission (AE) was employed to characterize the hydraulic fracturing processes. The experimental results show that for different temperatures the fracture geometry is almost unchanged, whereas the injection pressure curves, spatial distribution of AE energy, and AE-based source mechanisms are significantly changed. (1) At 120°C, The fracture pressures are increased by 3.6~4.9MPa and two remarkable pressure peaks appear at the injection pressure curves, implying the hydraulic fracture propagates intermittently with increasing resistances. (2) The spatial distributions of AE energy delineate a microcrack-band distributing along the hydraulic fracture. At the high temperature (120°C), the effective width of the microcrack-band is reduced by 40~56.4%, and the fracture energy is reduced by about 75% adjacent to the wellbore (about 40% of the fracture length) in the microcrack-band. (3) Based on the AE source analysis, the fracture mechanisms in the microcrack-band indicate the high-temperature (120°C) reduces the proportion of shear microcracks by 6~12%. The characteristics of high-temperature reducing the effectiveness of EGS hydraulic fracturing are due to the change in granite microstructures from temperature induction and the transient temperature differential (ΔT) between granite and fracturing fluid. In the EGS hydraulic fracturing, the net pressure should be enhanced in real-time with hydraulic fracture propagation to avoid fracturing arrest, ΔT between high-temperature granite and fracturing fluid should be lowered to enlarge the stimulated reservoir volume, and the proppant is suggested to be appropriately placed to prevent the further reduction of the fracturing effectiveness from fracture closures.