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The sealing performance of a reciprocating seal degrades during service. The analyses developed based on the initial state of a seal cannot express the performance degradation due to seal wear in detail. In this research, the Archard model in dry friction is extended to mixed lubrication by introducing the lubrication coefficient verified by an experiment. The nonlinear adaptive meshing technique is used in finite element analysis (FEA) to simulate the material removal to obtain the static contact pressure during the wear process. Hence, a sealing performance degradation analysis method is proposed based on the modified Archard model for reciprocating seals under mixed lubricating conditions. This method can be used to analyse the sealing, lubrication, and wear characteristics of seals at any service time. The simulation results indicate that the static pressure becomes more uniform with the occurrence of seal wear, and the lubricating property of the oil film reduces the seal wear. The variation trends of the sealing performance parameters such as contact pressure, friction, and net leakage at different service times under specific operating conditions are obtained.

In recent years, with the aggravation of energy crisis and environmental pollution, the Common Pressure Rail (CPR) system with great energy saving potential has become a research hotspot in the hydraulic research area. However, as the key component of CPR system, hydraulic transformers have the problems of low efficiency and poor control effect, which limit its practical application. The main contribution of the paper is to propose a new type of double-variable hydraulic transformer (DVHT) and address the control issue. As the displacement is adjustable, DVHT can achieve pressure regulation while maintaining the cylinder speed in the high-efficiency area. According to the system characteristics, a new control strategy is designed for the two control variables, and an adaptive integral terminal sliding mode controller is proposed to guarantee the robustness of the system. The simulation results prove the feasibility of the DVHT and show that the control method can achieve multitasking control and effectively improve the control effect.

Productivity Index (PI) decline is caused by different mechanisms in both the wellbore region and the far field. The damages in the wellbore region can be simulated by detailed wellbore modeling. To incorporate field pressure evolution and impact on well productivity, a newly developed full-field and near-wellbore poromechanics coupling scheme is used to model PI degradation against time. Near wellbore damages, field and well interactions are identified when applying the coupling scheme for a deep water well. History matching, production forecast and safe drawdown limits are derived for operation decisions. The coupling scheme is applied in a deep water well for history matching and drawdown strategy evaluation. The field model containing reservoir properties and operation conditions is coupled to multiple near-wellbore models which have completion and detailed wellbore geometry. During history matching, the field model is explicitly coupled with near-wellbore models. Field pressure is dynamically mapped into near-wellbore models and the PI multiplier in the field model for the given well(s) is updated based on near wellbore flow paths simulated in the near-wellbore models. Well productivity changes are accurately represented in the reservoir model for history matching and the production forecast. Using the coupling scheme, we successfully history matched well production and the PI trend. PI decline damage mechanisms, such as perforation efficiency, fines migration, fracture connectivity, fracture conductivity, compaction, are modeled in the coupling scheme. At each coupling step, well productivity calculated in near-wellbore model(s) is updated as a PI multiplier for the well(s) in the field model. History matching results showed the dominant PI decline factors are perforation efficiency, fines migration, and fracture conductivity. Near wellbore perforation collapse reduces flowing area and changes flow path. Fines migration is observed at the high velocity region. It damages the permeability around high velocity flow path and the damage accumulates with time. Maintaining perforation efficiency and conducting a stimulation job to remove fines damage could mitigate PI decline. Production forecast is performed with different drawdown rates. Results showed that there is no further PI decline with low drawdown. For high drawdown rate, PI could continue to decline and PI decline slope is related with drawdown pressure.

Summary Effective proppant placement has been one of the key objectives of hydraulic fracturing. Different proppant and fracture fluid characteristics and placement methodologies have been historically applied based on learnings from standard proppant transport studies with parallel plate slots. The standard test setup represents a simplified planar fracture with constant width and confined height, incorporating only basic flow characteristics, and thus, is inadequate to capture unique phenomena of proppant transport in unconventional reservoirs. In this study, proppant transport laboratory tests were conducted on a large-scale (10×20 ft) tortuous slot flow system. This novel setup incorporates many significant unconventional fracture features, including lateral and vertical tortuosity, variable width, leakoff, fluid dynamics replicating upward fracture growth, and so on. Proppant transport behavior was investigated with multiple parameters such as proppant size, density, and concentration; fracture fluid type and viscosity; pumping sequence; pump rate; and fracture properties (width, leakoff location and rate, fracture tortuosity profile, and flow directions). The detailed parametric and integrated study of test results includes analysis of proppant dune evolution, dune shape, particle-size distribution across dune, propped area, fluid, and proppant collected from leakoff and exit ports. Multiple unique phenomena occurring at tortuous interfaces were observed, including the generation of isolated pockets of proppant pack, restriction of upward movement owing to proppant bridging, and creation of discontinuous and sparsely distributed proppant pillars above the dune. The test results demonstrated a larger proppant dune angle in front of the dune peak during injection and a subsequent falloff of proppant pack with a higher percentage of smaller mesh proppant backfilling the area at and near the inlet (analogous to the wellbore). Self-segregation of proppant in slickwater as per mesh size resulted in higher percentage of smaller mesh (larger size) proppant settled near the injection point, and a higher percentage of larger mesh (smaller size) proppant placed farther in the system. These observations and novel learnings highlight that it is critical to account for tortuous fracture pathway, leakoff effects, and flow directions (both lateral and upward) to better understand proppant transport behaviors in unconventional fractures. A partially proppant-filled fracture area is recognized in unconventional fracture in addition to general classification of propped and unpropped fracture area. Using proppant with large mesh size distribution range or pumping smaller mesh proppant first in slickwater helps achieve dual benefits of higher near-wellbore conductivity and improved far-field transport. This study demonstrates and physically verifies unique proppant transport behaviors in unconventional hydraulic fractures. It also provides novel learnings that will help the industry to optimize hydraulic fracture design through the selection of optimum proppant and fluid properties with enhanced pumping strategies for overall well productivity improvement in an unconventional reservoir.

Summary The objective of this study is to understand how microseismic events are generated during hydraulic fracturing, as well as the role of geomechanical conditions (i.e., stress and mechanical stratigraphy) in this process. In the industry, microseismic event clouds have been generally used as an “outer boundary” of the “stimulated reservoir volume” (SRV). However, by comparing with other surveillance data (low-frequency distributed acoustic sensing, or LF-DAS, strain) in the Hydraulic Fracturing Test Site (HFTS) 2 experiment, we show that this assumption is fundamentally flawed. The HFTS 2 data have three unique observations that have not been commonly observed in other datasets: (1) Due to the influence of offset pad depletion, microseismic data show that hydraulic fractures from the child well can propagate over 3,000 ft into the depleted low-stress zone. (2) By comparing microseismic and horizontal fiber LF-DAS strain data, we observe that the microseismic event cloud does not necessarily reflect the created hydraulic fracture volume. Particularly, the extent of microseismic event clouds near heel stages is much shorter than what is shown with LF-DAS strain data. (3) Microseismic event magnitudes are larger in the depleted regions. Through geomechanical analysis, we demonstrate that the “bedding-plane-slip” model is likely the mechanism for microseismic generation during hydraulic fracturing. This model successfully explains the above field observations from the HFTS 2 experiment. We also provide a quantitative relationship connecting the microseismic event magnitude with fracture width increment and layer mechanical property contrast.

Summary Understanding fracture height growth can be of great significance to optimizing field development and improving recovery. The Hydraulic Fracturing Test Site 2 (HFTS-2) has provided a unique opportunity and an advanced data set to allow us to observe and understand fracture geometries rigorously. Low-frequency distributed acoustic sensing (LF-DAS) data from a vertical well in HFTS-2 showed three key observations: (i) excessive upward height growth (>1,000 ft) and limited downward growth of the hydraulic fractures during pumping, (ii) considerable additional upward fracture height growth (~300 ft) after well shut in, and (iii) very complex LF-DAS strain rate patterns for a small fiber-to-stage offset. Advanced geomechanical modeling was performed to simulate the hydraulic fracture propagation and the resulting strain responses in the vertical direction. The modeling results demonstrated asymmetric upward and downward fracture height growths as observed in HFTS-2 with a similar upward height growth rate. Simulated waterfall plots of vertical strain rate showed distinct patterns for different fiber-to-fracture distances. The upward-growing fracture tip can be clearly identified by the interfaces between compressing and extending zones. It was also found that the complex strain rate patterns observed in HFTS-2 for small fiber-stage offsets were not caused by the mechanical layering but possibly result from the simultaneous propagation of multiple hydraulic fractures at different rates. The simulation results improved the understating of the HFTS-2 LF-DAS data, and the simulated strain rate patterns could also serve as templates for fracture height interpretation from LF-DAS data in future.

Summary Multistage plug and perforation (plug-n-perf) fracturing is commonly used for horizontal well completion in unconventional reservoirs. Uniform distribution of proppant across all clusters in each stage has proved to be challenging with low viscosity slickwater owing to its limited transport capability. Computational fluid dynamics (CFD) has been used to model proppant transport in wellbore to improve perforation and fracturing design for achieving uniform proppant placement. However, traditional CFD modeling of a full-scale stage is computationally expensive, which limits its applicability in the completion design optimization. A new approach was developed in this paper to efficiently predict proppant placement along a multicluster stage based on a machine learning (ML) model trained with extensive CFD modeling results. Its high computational efficiency permits quick sensitivity analyses to optimize perforation and fracturing designs. The new approach was validated against full-stage CFD modeling results as well as post-treatment field diagnostics. Sensitivity analyses show that proppant inertia effect is a key factor affecting proppant placement in heel clusters with higher slurry flow rates, allowing more proppant carried to the toe owing to its higher density in comparison with fluid. Proppant settling allows bottom perforations to accept more proppant than top perforations. This gravitational effect is not negligible near the heel at high flow rates and becomes more dominant near toe clusters where the flow rate is reduced. Near-uniform proppant placement is achievable via perforation design optimization by taking advantage of these two key mechanisms controlling proppant transport in horizontal wellbores. It is demonstrated that in-line perforating designs with all perforations having the same orientation in each cluster or the entire stage, especially with perforations at the bottom or on the side of the wellbore, improve the proppant placement uniformity. However, it is recommended that the optimum perforation design should be identified case by case depending on specific input parameters. The ML-based model developed in this study has overcome some of the limitations from existing models in the literature and is able to provide quick and yet reliable solutions to proppant placement prediction and design optimization.

Unlike high-viscosity fluids, proppant transport with slickwater inside fractures is complex, but most fracture models do not adequately describe it. These models solve proppant transport based on simplified continuity equations. They assume that the average proppant velocity is the same as the fluid velocity and proppant settling in the vertical direction is always incorporated using Stokes’ law or similar equations. Some models also include proppant bridging and trapping effects, and velocity slippage between proppant and fluid, using empirical correlations. None of these commercially available models consider proppant momentum and interactions of particles with other particles, fluids, and fracture walls. In addition, turbulent flow near wellbore is completely ignored in these models. Slot tests used for proppant transport in laboratory studies are too small and too simplified to upscale properly to realistic field conditions. CFD (computational fluid dynamics) modeling can bridge some of these gaps. The main objective of this study was to use CFD modeling for a comprehensive understanding of proppant transport with slickwater and improve proppant and fluid selections for unconventional fracturing.Several lab-scale CFD models were constructed and calibrated using experimental proppant transport data from slot flow tests. Field-scale CFD simulations were performed to evaluate the impact of key parameters on proppant transport and placement, including pumping rate, fracture width, fluid viscosity, proppant size and density, fluid leakoff, fracture height growth, perforation orientation and size, multiple fractures near wellbore, and pre-existing dunes, etc. Field-scale CFD model results show that proppant with wider size distribution provided more favorable placement, as larger proppant particles settle quickly to create a proppant dune and generate sufficient fracture conductivity near the wellbore. Smaller proppant particles travel deep into the fracture to increase partially propped fracture surface area in the far-field. CFD model results further show that the distance that larger proppant could reach inside the fracture is small, especially in the vertical direction, and that proppant height coverage can be improved by dune formation.CFD model results confirm that proppant placement inside the fracture is significantly affected by pumping rate, fracture width, fluid viscosity, proppant size and density. CFD model results suggest that horizontal wells should always be landed close to the bottom section of the expected fracture where the proppant dune is located. Proppant with wider size distribution, for example 40/140- and 40/200-mesh sand, is expected to provide improved proppant placement.

Summary Multistage plug-and-perforate fracturing of horizontal wells has proved to be an effective method to develop unconventional reservoirs. Various studies have shown uneven fluid and proppant distributions across all perforation clusters. It is commonly believed that both fracturing fluid and proppant contribute to unconventional well performance. Achieving uniform fluid and proppant placement in all perforation clusters is an important step toward optimal stimulation. This paper discusses how to achieve such uniform placement in each fracturing stage by means of a computational fluid dynamics (CFD) modeling approach. A laboratory-scale CFD model was built and calibrated using experimental data of proppant transport through horizontal pipes available from several laboratory configurations. A field-scale model was then built and validated using perforation erosion data from downhole camera observations. With the field-scale model validated, CFD simulations were performed to evaluate the impact of key parameters on fluid and proppant placement in individual perforations and clusters. Some key parameters investigated in this study included perforation variables (orientation, size, and number), cluster variables (count and spacing), fluid properties, proppant properties, pumping rates, and stress shadow effects. Both laboratory and CFD results show that bottom-side perforations receive significantly more proppant than top-side perforations because of gravitational effects. Laboratory and CFD results also show that proppant distribution is increasingly toe-biased at higher rates. Proppant concentration along the wellbore from heel to toe varies significantly. Gravity, momentum, viscous drag, and turbulent dispersion are key factors affecting proppant transport in horizontal wellbores. This study demonstrates that near-uniform fluid and proppant placement across all clusters in each stage is achievable by optimizing perforation/cluster variables and other treatment design factors. CFD modeling plays an important role in this design-optimization process.

Proppant production could damage downhole and surface equipment, reduce well performance, and lead to workover operations. Production rate control, drawdown management and solid separation at surface are often used for unconventional wells. An in-depth understanding of factors affecting proppant production is a crucial step toward mitigating the issues. An experimental investigation was conducted to determine key parameters affecting proppant production and develop mitigation strategies. This study led to the construction of a unique fracture cell, inside which a proppant pack is sandwiched between two rock platens with similar reservoir formations. The fracture cell can be configured horizontally or vertically to mimic different fracture orientations. To simulate flowback process, slickwater is injected from the inlet boundary and produced through perforations at the outlet boundary, while injection rate and confining stress are increased gradually. Low-viscosity oil or a mixture of oil/slickwater is injected to simulate production operations. Injection rate, stress, proppant production and pack width vs. time are recorded. After each test, a novel technique is used to preserve the shape of the channel created by proppant production. Twenty five tests were performed using raw, resin-coated, and surfactant-treated frac sands (40/70 and 100 mesh). Lab results show that proppant pack failure and proppant production initiate at perforations when fluid flow velocity is above a critical value, creating a channel progressing outwards from perforations. Channel growth continues until the proppant pack becomes stabilized due to reduced velocity through the channel. Proppant production and channel growth are more severe in vertical fractures than horizontal ones. In vertical fractures, gravity effects make the proppant at the arc area above the channel unstable and become mobile. At irreducible water saturation, the proppant pack is more stable in the presence of oil. Once water is mobile, proppant production becomes more severe. Altering the proppant surface to hydrophobic reduces channel size and proppant production. Resin-coated sand (RCS) can stop or mitigate sand production if enough RCS is placed near the perforations. Proppant particle shape, proppant surface conditions (coating or wettability), multiphase effects, stress, flowrate, fracture orientation (vertical or horizontal), and ratio of fracture width to proppant size are recognized as key factors. The lab results led to a few cost-effective mitigation strategies: larger proppant near wellbore, local sand with lower sphericity/roundness during the entire treatment, and resin-coated or hydrophobic sand toward the end of treatment, etc. Based on learnings from this study, proppant sequencing trials were implemented, with 40/70-mesh sand pumped first, placed near wellbore, and followed by 100-mesh sand. Field trial results showed significant reduction of proppant production and solid separation cost. At the time of this writing, the evaluation of the hydrophobic frac sand was in progress.

Cryogenic fracturing with liquid nitrogen (LN2) offers the benefits of reducing the water consumption and adverse environmental impacts induced by water-based fracturing, as well as potentially enhancing the fracture complexity. We performed a series of laboratory experiments to explore the key mechanisms governing the breakdown pressures of shale during cryogenic fracturing. In this study, cylindrical shale samples were pre-conditioned by exposing a borehole to low-temperature LN2 for a certain time period, and then, the samples were fractured using gaseous N2 under triaxial stress and a high reservoir temperature. The effects of various key parameters on the breakdown pressure were investigated, including the duration of the low-temperature LN2 treatment, the confining pressure, the reservoir temperature, and the direction of the shale bedding relative to the borehole axis. The results demonstrate that the injection of low-temperature LN2 as a pre-fracturing fluid into a borehole can significantly reduce the breakdown pressure of the shale during subsequent nitrogen fracturing. This reduction in breakdown pressure can be further intensified by increasing the duration of the LN2 pre-conditioning. Without LN2 pre-conditioning, the breakdown pressure initially increases and then decreases with increasing reservoir temperature. When LN2 pre-conditioning is applied, the breakdown pressure keeps decreasing with increasing reservoir temperature. As the confining pressure increased, the breakdown pressure increased linearly in the tests with and without LN2 pre-conditioning. The experimental results demonstrate that LN2 pre-conditioning before N2 fracturing is a promising waterless fracturing technique that reduces the breakdown pressure and enhances the fracture complexity.

We explored the dependency of strength anisotropy on loading rate in coal both experimentally and numerically. An improved numerical modeling method was developed for this investigation to reduce the random error caused by the mechanical differences of coal specimens. After that, specimens with different anisotropy angles (the angle between the coring direction and bedding plane orientation) were processed (0°, 15°, 30°, 45°, 60°, and 90°). These specimens were then scanned by the X‐ray Computed Tomography (CT) and tested by unconfined loading frame. Uniaxial compressive simulations were performed on 15 numerical models with different anisotropy angles at various loading rates (1.0 × 10−6, 5.0 × 10−6, 10.0 × 10−6, and 20.0 × 10−6 mm/step). The results indicate that the uniaxial compressive strength (UCS) of coal generally first decreases and then increases as the anisotropy angle increases from 0° to 90° for all loading rates. It is also found that the UCS increases significantly with the increasing loading rate at anisotropic angles of 30° and 45°, while it is less obvious at anisotropic angles of 0° and 90°. This results in a reduced USC anisotropy at high loading rates. Meanwhile, a negative exponential equation is obtained to describe the variation of UCS with the loading rate at different anisotropic angles. And a unified equation is then developed and verified to define the UCS as a function of the loading rate and anisotropic angle.

We explored the microstructure-related scale effect on the tensile failure of coal. Disc specimens with different diameters (25 mm, 38 mm, 50 mm, and 75 mm) were processed for the Brazil split test. The influence of microstructures on fracture initiation and propagation was detected and analysed by the combination of X-ray computed tomography scanning, digital image correlation approach, and acoustic emission monitoring. The investigation indicated that tensile strength decreased with increasing specimen diameter, and the relationship can be described by an exponential equation. Four tensile failure modes were observed in specimens with different diameters, namely central, non-central, central edge, and central multiple pattern. Larger specimens exhibited more complicated failure patterns (central edge and central multiple failure patterns) and a greater percentage of shear failure fractures. Strain concentration and strain reversal were observed, respectively, in mineral—inclusion-rich regions and pre-existing discontinuities regions. This possibly contributed to fracture initiation, propagation, and coalescence. Fractures tended to grow along with the interface of mineral inclusion and coal matrix, and they could have propagated into and connect the pre-existing discontinuities. The greater volume of microstructure in larger specimens resulted in fractures that were more complex and may have increased the number of shear failure cracks and led to failure modes that were more complicated.

BackgroundTo study the lncRNA-mRNA interaction network structure and analyze the possible target mRNAs among the differentially expressed lncRNAs between healthy adults, newly diagnosed multiple myeloma patients, and refractory relapsed multiple myeloma patients.MethodsPublic sequence data files were downloaded from the Sequence Read Archive (SRA). Totally 23 RNA-seq samples (GSE110486) related to myeloma published in 2018 (including transcriptome data of bone marrow plasma cells from healthy adults, newly diagnosed multiple myeloma patients and recurrent patients) were acquired, further analyses of differential lncRNAs, lncRNAs-mRNA co-expression, and WGCNA expression module and cis regulatory gene were performed. In addition, we performed differential expression analysis of lncRNAs and enrichment analysis of target mRNA regulated by lncRNAs from multiple myeloma patients and healthy controls which in order to verify the functions of these lncRNAs and their target mRNAs.ResultsFrom the transcriptional samples in this study,1006 new lncRNAs were identified, which including 707 lncRNAs specifically up-regulated and 283 specifically down-regulated in relapsed myeloma. The mRNA genes co-expressed with specific lncRNAs in relapsed multiple myeloma were mainly enriched in the extracellular matrix organization, platelet activation, cell adhesion, inflammation response, T cell co-stimulation and immune response pathways. Target mRNA regulated by DE lncRNAs including IL23R, ELF3, IL32, TMIGD2, CD28, CD5, TNF, CX3CR1, ADAMTS20 etc, by GO analysis, these target genes were enriched into many biological processes, such as innate immunity, apoptosis and positive regulation of apoptosis. The cis-regulated lncRNA of these target mRNAs include U62631.5, XLOC_062939 and XLOC_027240, and their cis-regulatory targets include CD22, SSX1 and DCC. lncRNAs and enrichment analysis of target mRNA regulated by lncRNAs from multiple myeloma patients and healthy controls was consistent with the previous analysis.ConclusionTarget mRNAs regulated by DE lncRNAs and their cis-regulatory targets are involved in the immune cells remodeling of gene expression patterns during multiple myeloma relapse, and may have an important function in this pathological process, it deserves further study as a potential target for the treatment of multiple myeloma.

We adopted regimen of obinutuzumab, venetoclax, lenalidomide and zanubrutinib combined with intrathecal injection to treat a relapsed high risk CLL patient with CNS involvement, who have progressed underwent two cycles therapy of zanubrutinib combined with BR regimen previously. After two cycles therapy, no malignant cells were identified in the cerebrospinal fluid (CSF) and radiological assessment showed a partial remission, as well, radiological complete remission was achieved after three cycles of therapy. Combined immunochemotherapy may have a higher response rate and could be an alternative option for CNS involvement in CLL patients.

Simple plugging of the high-permeability “thief zones” of oil reservoirs is the most plausible and also the most straightforwardly achievable approach to enhance sweep efficiency and oil recovery. Sporosarcina pasteurii is a representative microorganism with the ability to precipitate calcium carbonate (CaCO3) via enzymatic hydrolysis of urea in the presence of calcium ions. Microbially induced calcium carbonate precipitation (MICP) can cement and seal the granular and fractured media and thus can be used as a potential microbial plugging agent for the high-permeability zones of oil reservoirs. The following investigated the microscopic characteristics of MICP plugging and its efficacy in permeability reduction. The columns of near-spherical silica sand and angular silica sand with three separate granularities (40/60, 60/80, and 80/120 mesh) were used as artificial rock cores representing distinct pore sizes and pore characteristics to investigate the efficacy and microprocess of MICP plugging with different biotreatment periods. The results indicated that permeability is reduced significantly after only short periods of biotreatment. After eight cycles of MICP treatments, the permeability for each type of cores dropped by 54–90% of individual initial permeabilities. The measured CaCO3 content indicated that the decreasing rate in permeability with the increasing CaCO3 content experiences three contrasting stages, namely, slow decline, speedy decline, and plateauing. X-ray diffraction indicated that most of the generated CaCO3 crystals occur as vaterite with only a small amount of calcite. Imaging by scanning electron microscopy further revealed the microprocess of MICP plugging. Microorganisms first concentrate on the pore wall to secrete CaCO3, forming a thin and large uniform layer of CaCO3. Then, some nucleation sites of CaCO3 crystals will experience further preferential growth, resulting in large, dominant crystals that act as a plugging agent within the pore space. Compared to extracellular polymeric substances, which are currently the primary microbial plugging agent used to enhance sweep efficiency of oil reservoirs, bio-CaCO3 appears more effective in plugging in terms of its morphology, size, and growth characteristics.

Two key goals for proppant selection and injection optimization are economical mitigation of proppant flowback and achieving optimum conductivity throughout fracture area from near wellbore to far field. Improvements in these areas benefit project economics through cost reduction and production uplift. This paper highlights the implementation learnings and success results of CounterProp to reduce proppant flowback and increase near wellbore conductivity in Permian shale and tight development. CounterProp proppant injection sequence (large particle size proppant pumped first before small particle size) was introduced by Ely et al (2019) in the paper SPE-194370-MS for slickwater treatment in low permeability shale and tight reservoirs. Two internal studies were carried out to validate CounterProp design impacts. Hydraulic fracture simulation models were completed, and laboratory study was performed to improve understanding of proppant transport behavior and evaluate impact of CounterProp. The laboratory study used large-scale tortuous slot flow equipment with slickwater and different proppant sizes and sequences. The model and laboratory study results indicated that larger proppant settled near wellbore, creating a barrier to prevent smaller proppant grains moving into the wellbore, thereby mitigating proppant flowback and generating higher fracture conductivity in near wellbore area. An iterative and phased approach for field implementation was applied to reduce the execution risk of injecting large size 40/70 mesh proppant before small size 100 mesh with slickwater. Multiple field trials have been executed since late 2019 in both the Midland Basin and Delaware Basin. The first trial was implemented in a Lower Spraberry development in Midland Basin where proppant flowback was not an issue, a production uplift was expected with higher near wellbore conductivity, and the perceived execution risk was minimal. In Lower Spraberry, a range of median uplift from 5-42% cumulative oil was measured compared to offset control pads. In Delaware Basin, proppant flowback during early production phase is an issue handled with surface sand separator equipment, and the goal for CounterProp was to reduce the time and cost of sand separator equipment on location. CounterProp was implemented in multiple Wolfcamp developments in Delaware Basin with no execution issues and resulted in decreased proppant production compared to similar developments thereby allowing release of proppant flowback management equipment from these locations approximately 70% earlier, contributing to savings and production benefit with higher pressure drawdown allowed. This paper shares a success story from specific examples of CounterProp applications with slickwater in Permian low permeability shale and tight reservoirs. CounterProp field trials have proven as low risk solutions for unconventional development with large potential upside of cost reduction from proppant flowback mitigation and production improvement with higher near wellbore conductivity. Further, application may be broad in Permian development, with low cost, low execution risk, and high benefit to long-term production and operations.

Control issue is the key for applying hydraulic hybrid system, especially for common pressure rail (CPR) system which has the huge potential to enhance efficiency. In the paper, the mathematical model of hydraulic cylinder speed control system using new hydraulic transformer is established. Then an adaptive fuzzy sliding mode controller based on Pi-sigma fuzzy neutral network is designed to solve the problem of parameter uncertainty and nonlinearity without establishing the precise model. Furthermore, compared to PID and conventional adaptive fuzzy system, the controller proposed can achieve good control performance and strong robustness in the presence of time-varying uncertainty.

In order to solve the control problem of the hydraulic cylinder controlled by a new hydraulic transformer for its parametric coupling and intrinsic nonlinearity, a state estimation based fuzzy sliding mode velocity controller is proposed in this paper. Firstly, the basic principle of new hydraulic transformer is analyzed and the established system model is improved; then external disturbances are estimated by the method of extended state estimation. Moreover, the fuzzy method is combined with the estimation method to compensate the obtained external disturbances, such that the minimization of switching gain can be realized under the condition that the arrival condition of the sliding mode is guaranteed, then fuzzy self-tuning of switching gain is performed.

Multi-stage plug-n-perf fracturing of horizontal wells has proven to be an effective method to develop unconventional reservoirs. Various studies have shown uneven fluid and proppant distributions across all perforation clusters. It is commonly believed that both fracturing fluid and proppant contribute to unconventional well performance. Achieving uniform fluid and proppant placement is an important step toward optimal stimulation. This paper discusses how to achieve such uniform placement in each stage via a CFD (Computational Fluid Dynamics) modeling approach. CFD models in several lab scales were built and calibrated using experimental data of proppant transport through horizontal pipes in several laboratory configurations. A field-scale model was then built and validated using perforation erosion data from downhole camera observations and the same model parameters calibrated in the lab-scale model. With the field-scale model validated, CFD simulations were performed to evaluate the impact of key parameters on fluid and proppant placement in individual perforations and clusters. Some key parameters investigated in this study included perforation parameters (size, orientation, number), cluster spacing, cluster count per stage, fluid properties, proppant properties, pumping rates, casing sizes, and stress shadow effects, etc. Both lab and CFD results show that bottom-side perforations receive significantly more proppant than top-side perforations due to gravitational effects. Lab and CFD results also show that proppant distribution is increasingly toe-biased at higher rates. Proppant concentration along the wellbore from heel to toe generally varies significantly. Gravity, momentum, viscous drag, and turbulent dispersion are key factors affecting proppant transport in horizontal wellbores. This study demonstrates that near-uniform fluid and proppant placement across all clusters in each stage is achievable by optimizing perforation, cluster, and other treatment design factors. Validated CFD modeling plays an important role in this design optimization process.

Defining the trajectory of hydraulic fractures crossing bedding planes and other fractures is a significant issue in determining the effectiveness of the stimulation. In this work, a damage evolution law is used to describe the initiation and propagation of the fracture. The model couples rock deformation and gas seepage using the finite element method and is validated against classical theoretical analysis. The simulation results define four basic intersection scenarios between the fluid-driven and preexisting fractures: (a) inserting—the hydraulic fracture inserts into a bedding plane and continues to propagate along it; (b) L-shaped crossing—the hydraulic fracture approaches the fracture/bedding plane then branches into the plane without crossing it; (c) T-shaped crossing—the hydraulic fracture approaches the fracture/bedding plane, branches into it, and crosses through it; (d) direct crossing—the hydraulic fracture crosses one or more bedding planes without branching into them. The intersection scenario changes from (a) → (b) → (c) → (d) in specimens with horizontal bedding planes when the stress ratio β ( β = σ y / σ x ) increases from 0.2 to 5. Similarly, the intersection type changes from (d) → (c) → (a) with an increase in the bedding plane angle α (0° → 90°). Stiffness of the bedding planes also exerts a significant influence on the propagation of hydraulic fractures. As the stiffness ratio E 1 ¯ / E 2 ¯ increases from 0.1 to 0.4 and 0.8, the seepage area decreases from 22.2% to 41.8%, and the intersection type changes from a T-shaped crossing to a direct crossing.

Non-aqueous or gaseous stimulants are alternative working fluids to water for hydraulic fracturing in shale reservoirs, which offer advantages including conserving water, avoiding clay swelling and decreasing formation damage. Hence, it is crucial to understand fluid-driven fracture propagation and morphology in shale formations. In this research, we conduct fracturing experiments on shale samples with water, liquid carbon dioxide, and supercritical carbon dioxide to explore the effect of fluid characteristics and in situ stress on fracture propagation and morphology. Moreover, a numerical model that couples rock property heterogeneity, micro-scale damage and fluid flow was built to compare with experimental observations. Our results indicate that the competing roles between fluid viscosity and in situ stress determine fluid-driven fracture propagation and morphology during the fracturing process. From the macroscopic aspect, fluid-driven fractures propagate to the direction of maximum horizontal stress direction. From the microscopic aspect, low viscosity fluid easily penetrates into pore throats and creates branches and secondary fractures, which may deflect the main fracture and eventually form the fracture networks. Our results provide a new understanding of fluid-driven fracture propagation, which is beneficial to fracturing fluid selection and fracturing strategy optimization for shale gas hydraulic fracturing operations.

Hydraulic fracturing is a widely used method for well stimulation to enhance hydrocarbon recovery. Permeability, or fluid conductivity, of the hydraulic fracture is a key parameter to determine the fluid production rate, and is principally conditioned by fracture geometry and the distribution of the encased proppant. A numerical model is developed to describe proppant transport within a propagating blade-shaped fracture towards defining the fracture conductivity and reservoir production after fracture closure. Fracture propagation is formulated based on the PKN-formalism coupled with advective transport of an equivalent slurry representing a proppant-laden fluid. Empirical constitutive relations are incorporated to define rheology of the slurry, proppant transport with bulk slurry flow, proppant gravitational settling, and finally the transition from Poiseuille (fracture) flow to Darcy (proppant pack) flow. At the maximum extent of the fluid-driven fracture, as driving pressure is released, a fracture closure model is employed to follow the evolution of fracture conductivity with the decreasing fluid pressure. This model is capable of accommodating the mechanical response of the proppant pack, fracture closure of potentially contacting rough surfaces, proppant embedment into fracture walls, and most importantly flexural displacement of the unsupported spans of the fracture. Results show that reduced fluid viscosity increases the length of the resulting fracture, while rapid leak-off decreases it, with both characteristics minimizing fracture width over converse conditions. Proppant density and size do not significantly influence fracture propagation. Proppant settling ensues throughout fracture advance, and is accelerated by a lower viscosity fluid or greater proppant density or size, resulting in accumulation of a proppant bed at the fracture base. ‘Screen-out’ of proppant at the fracture tip can occur where the fracture aperture is only several times the diameter of the individual proppant particles. After fracture closure, proppant packs comprising larger particles exhibit higher conductivity. More importantly, high-conductivity flow channels are necessarily formed around proppant banks due to the flexural displacement of the fracture walls, which offer preferential flow pathways and significantly influence the distribution of fluid transport. Higher compacting stresses are observed around the edge of proppant banks, resulting in greater depths of proppant embedment into the fracture walls and/or an increased potential for proppant crushing.

We explore microstructure-related effects of loading direction and specimen size on the anisotropy of uniaxial compressive strength in coal. We measure uniaxial compressive strength on coal samples of four different diameters (25 to 75 mm) and with varied dip of the bedding plane with respect to loading direction (0°, 15°, 30°, 45°, 60° and 90°) including characterizing the variation of microstructures in the specimens by X-ray imaging. The uniaxial compressive strength for each specimen size exhibits a unique U-shape curve against the angle of anisotropy ( Jaeger, 1971 ). The degree of the strength anisotropy decreases with increasing specimen size, principally due to the enhanced microstructural volume of a larger specimen. The contribution of microstructures on uniaxial compressive strength differs for different orientations of loading relative to anisotropy. The rate of decline of the average uniaxial compressive strength with increasing specimen size is greatest when loading is parallel to bedding (anisotropic angle of 0°) and is the most moderate at 45°. An empirical equation relating specimen diameter with uniaxial compressive strength is proposed and verified against the experimental data. Based on this equation, the UCS of coal samples with different orientations relative to the anisotropy are predicted for the limiting sizes of zero and ∞. The anisotropy of the scale effect is also explored. Meanwhile, it is verified that a cosine relation between anisotropy angle and uniaxial compressive strength is applicable to coal specimens of different sizes. This demonstrates that the strength anisotropy in coal will remain constant when the specimen diameter is larger than a critical threshold. Based on these two observations/equations, a universal equation relying on the minimum strength angle, friction angle and Weibull coefficients is proposed and verified against experimental data to describe the relationship among anisotropy angle, specimen size, and uniaxial compressive strength in coal.

Hydraulic fracturing is a key method in the stimulation of shale gas reservoirs. Shale gas formations often contain natural fractures which are fluid-pressure sensitive and dilate in response to the inflation of the fracture, increasing fluid loss and slowing down and potentially prematurely arresting fracture propagation. Models typically assume 1-D single-porosity/permeability (Carter) leakoff perpendicular to the hydraulic fracture. However, the leakoff process in naturally fractured formations is considerably more complex. In this study, we present an hydraulic fracturing model based on the PKN-formalism which accommodates leakoff into a pressure-sensitive dual porosity medium. Proppant transport is accommodated by introducing empirical constitutive equations to determine the proppant distribution during the hydraulic fracturing treatment. The model is solved numerically and is validated against known small and large time asymptotic solutions. The model is capable of providing a rapid estimation of the morphology of hydraulic fractures in naturally fractured formations and the corresponding proppant distribution. The simulation results illustrate that the leakoff into a dual porosity medium, where fracture permeability is a strong function of applied fluid pressure, results in a reduced length of the propagating fracture due to the fugitive fluid leakoff from the fracture into the surrounding formation and that this in turn results in a reduced maximum width during the treatment. The ability to infuse proppants in fluid-driven fractures penetrating large distances from the injection wellbore is further limited by premature screen-out. This may compromise the ultimate efficiency of the final hydraulic fracture regarding gas recovery. Reduced propagation and premature screen-out are limited by low permeability and large spacing of the natural fractures. The presence of an existing network of natural fractures, including those adjacent to the hydraulic fracture that may become propped, aids in the recovery of the resource by reducing diffusion lengths of the hydrocarbon to the main fracture.

The residual opening of fluid-driven fractures is conditioned by proppant distribution and has a significant impact on fracture conductivity - a key parameter to determine fluid production rate and well performance. A 2D model follows the evolution of the residual aperture profile and conductivity of fractures partially/fully filled with proppant packs. The model accommodates the mechanical response of proppant packs in response to closure of arbitrarily rough fractures and the evolution of proppant embedment. The numerical model is validated against existing models and an analytic solution. Proppant may accumulate in a bank at the fracture base during slick water fracturing, and as hydraulic pressure is released, an arched zone forms at the top of the proppant bank as a result of partial closure of the overlaying unpropped fracture. The width and height of the arched zone decreases as the fluid pressure declines, and is further reduced where low concentrations of proppant fill the fracture or where the formation is highly compressible. This high-conductivity arch represents a preferential flow channel and significantly influences the distribution of fluid transport and overall fracture transmissivity. However, elevated compacting stresses and evolving proppant embedment at the top of the settled proppant bed reduce the aperture and diminish the effectiveness of this highly-conductive zone, with time. Two-dimensional analyses are performed on the fractures created by channel fracturing, showing that the open channels formed between proppant pillars dramatically improve fracture transmissivity if they are maintained throughout the lifetime of the fracture. However, for a fixed proppant pillar height, a large proppant pillar spacing results in the premature closure of the flow channels, while a small spacing narrows the existing channels. Such a model provides a rational means to design optimal distribution of the proppant pillars using deformation moduli of the host to control pillar deformation and flexural spans of the fracture wall.

Relative to water-based fluids, non-aqueous fracturing fluids have the potential to increase production, reduce water requirements, and to minimize environmental impacts. Since the viscosity of supercritical CO2 is one-tenth that of water, its density is close to that of water, and is capable of promoting sorptive rejection of methane, it is an attractive substitute for water in the extraction of shale gas and coalbed methane. The following defines a geomechanical model accommodating the interaction of fluid flow, adsorption-induced swelling stress, solid deformation and damage to quantify rock-gas interactions during supercritical CO2 fracturing for shale gas production. The architecture of the shale is accommodated that includes both pore- and micro-crack-based porosity. According to the microcrack model representing shales with low porosity, both analytical and numerical results show that the effective stress coefficient is much smaller than unity. We analyze the potential advantages of fracturing using supercritical CO2 including enhanced fracturing and fracture propagation, increased desorption of methane adsorbed in organic-rich portions of the shale and the potential for partial carbon sequestration. Rock-gas interactions include both the linear poroelastic response and the chemo-mechanical interaction due to sorption. Simulation results demonstrate that supercritical CO2 fracturing indeed has a lower fracture initiation pressure and a significantly lower breakdown pressure, as observed in experiments, and that fractures with greater complexity than those developed with liquid CO2 and water fracturing result. With increasing dynamic viscosity of the fracturing fluids, the predicted breakdown pressure also increases, consistent with experimental observations.

Hydraulic fracturing operations have been widely used to enhance reservoir permeability during the extraction of oil, shale gas and tight sandstone gas. Recently, non-aqueous fracturing fluids, such as supercritical carbon dioxide and nitrogen, have been proposed as the potential fracturing fluid candidates due to their advantages of decreasing formation damage, conserving water resources and avoiding injection-induced seismicity. However, the breakdown process of the non-aqueous fracturing process and the breakdown mechanism remain mysteries. In this research, we report a series of hydraulic fracturing experiments with low-permeable shale samples and high-permeable sandstone samples by water, supercritical carbon dioxide, and nitrogen gas under different injection rates. Moreover, we use a coupled fluid-rock interaction model to visualize the distribution of fluid pressure near the injection borehole during hydraulic fracturing before the sample breakdown. The results indicate that the fluid infiltration decreases the breakdown pressure by increasing the pore pressure and decreasing the effective stress, especially for high-permeable sandstone rock and low-viscosity fracturing fluid. Also, breakdown pressure increases with increasing fluid injection rate, and the conventional Hubbert-Willis and Haimson-Fairhust equations can still effectively determine the upper and lower limits in predicting the breakdown pressure. Our results suggest that lower viscosity fluid with a lower injection rate leads to a lower breakdown pressure, which is suitable to be implemented for the reservoirs with high intrinsic permeability.

Conventional water-based fracturing treatments may not work well for many shale gas reservoirs. This is due to the fact that shale gas formations are much more sensitive to water because of the significant capillary effects and the potentially high contents of swelling clay, each of which may result in the impairment of productivity. As an alternative to water-based fluids, gaseous stimulants not only avoid this potential impairment in productivity, but also conserve water as a resource and may sequester greenhouse gases underground. However, experimental observations have shown that different fracturing fluids yield variations in the induced fracture. During the hydraulic fracturing process, fracturing fluids will penetrate into the borehole wall, and the evolution of the fracture(s) then results from the coupled phenomena of fluid flow, solid deformation and damage. To represent this, coupled models of rock damage mechanics and fluid flow for both slightly compressible fluids and CO2 are presented. We investigate the fracturing processes driven by pressurization of three kinds of fluids: water, viscous oil and supercritical CO2. Simulation results indicate that SC-CO2-based fracturing indeed has a lower breakdown pressure, as observed in experiments, and may develop fractures with greater complexity than those developed with water-based and oil-based fracturing. We explore the relation between the breakdown pressure to both the dynamic viscosity and the interfacial tension of the fracturing fluids. Modeling demonstrates an increase in the breakdown pressure with an increase both in the dynamic viscosity and in the interfacial tension, consistent with experimental observations.