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Abstract Oil transport is greatly affected by heterogeneous pore–throat structures present in shale. It is therefore very important to accurately characterize pore–throat structures. Additionally, it remains unclear how pore–throat structures affect oil transport capacity. In this paper, using finite element (FE) simulation and mathematical modeling, we calculated the hydrodynamic resistance for four pore–throat structure. In addition, the influence of pore throat structure on shale oil permeability is analyzed. According to the results, the hydrodynamic resistance of different pore throat structures can vary by 300%. The contribution of additional resistance caused by streamline bending is also in excess of 40%, even without slip length. Furthermore, Pore–throat structures can affect apparent permeability by more than 60% on the REV scale, and this influence increases with heterogeneity of pore size distribution, organic matter content, and organic matter number. Clearly, modeling shale oil flow requires consideration of porous–throat structure and additional resistance, otherwise oil recovery and flow capacity may be overestimated.

Deep reservoirs have a large difference in geo-stress, and compared to shallow reservoirs, multiple clusters of fracturing are usually required to effectively improve the quality of reservoir reconstruction. In this paper, considering the relevant geological parameters of a certain reservoir in the southwest, multi-cluster reservoir fracturing models under three-dimensional conditions based on the cohesive element modelling method are established. Then, the quantitative rules of fluid pressure, fracture length, fracture aperture, fracture area, tensile failure rate, and the fractal dimension of fracture morphology under different fracturing cluster numbers were revealed. The results show that compared to conventional fracturing, multi-cluster fracturing can significantly increase the number of main fractures and improve the effectiveness of reservoir reconstruction. As the number of clusters increases, the number of main fractures in the reservoir increases, but it can also lead to the increase of small opening fractures, which may be unfavourable for the pumping of proppant and subsequent mining. Meanwhile, based on the fractal dimension results of fracture morphology, it was found that under this simulation condition, the number of fracturing clusters had a significant impact on the fractal dimension of fracturing fractures before the fracturing of six clusters, while after the fracturing of six clusters, the impact of the number of fracturing clusters on the fractal dimension of fracturing fractures decreased. Therefore, when considering factors such as the complexity of fractures, multi-cluster fracturing does not necessarily result in more fracturing clusters being better but should be comprehensively considered for optimization. This study has certain reference significance for selecting the spacing between multiple fracturing clusters.

Hydraulic fracturs size inversion plays an important role on evaluating hydraulic fracturing efficiency. Fracture size can be calculated by microseism events or all the pressure data generated by hydraulic fracturing stimulations. These methods are time-consuming. However, the sudden shutoff of pumping can induce a special data known as the water hammer signal. The size of this data is much fewer than others so using it to calculate fracture size is efficient. This study proposes a method of using water hammer signal to work out the hydraulic fracture size. The numerical simulation model is proposed based on the transient flow model to describe the water hammer behavior. The impacts of fracture on water hammer behavior are represented by three parameters (R,C and I). Through these parameters, the fracture size can be calculated. The accuracy of this method is validated by comparing fracture size inversion results between different methods. The results show that the parameter C and R have obvious impacts on water hammer signal and they can cause the amplitude of water hammer signal alternate from 5 to 2 MPa. In addition, this method is accurate for fracture size calculation and the overall error between its results and ones from normal methods is about 6.28%. This method is more suitable for fractures away from horizontal well toe than ones near to well toe. The mean error of fractures away from well toe is only 3.49% but it is 12.75% for fracture near well toe. It is because that the fracture structure is complex near well toe. It indicates that the more accurate relationship between fracture size and parameters (R,C and I) is required for fracture with complex structure.

Most of current permeability evaluation models for shale gas reservoirs ignore the influence of imbibition during fracturing, moreover, several of the considerations are different from real conditions, for example, shale pore shape is circular and water film is with equal thickness, which is convenient for calculation but adverse to evaluation accuracy. In the study, shale pore shapes are closer to ellipse by statistically analyzing the scanning electron microscopy results, the thickness of water film is not equal on elliptical pore surface but related to the curvature. Based on these new insights, a quantitative model for determining the unequal thickness of water film was established, and then a new multi-scale elliptical pore permeability model, considering non-equal-thickness water film, wall roughness, stress sensibility, and retention effect, was established based on the multi-scale flow weighting theory. The prediction results of this permeability model are similar to the test results, and are more accurate than that of the previous models. Finally, factors analysis showed that the effect of roughness on permeability was small, but the negative impact of water film and stress sensitivity on permeability was significant.

Abstract The spontaneous imbibition (SI) process in shale oil reservoirs is not only influenced by capillary force, but also by the osmotic pressure between the fracturing fluid and formation water in the nanopores media. In this study, experimental methods are used to investigate the mechanisms of osmosis in the SI, taking into account the presence of initial formation water in shale oil reservoirs. To investigate the effect of osmosis, SI experiments were performed on the fine-grained felsic shale of the Qikou sag of Dagang oilfield. Low-field NMR testers and high-precision electronic balances are utilized for the measuring of oil–water migration. The results show that, when S w ≠ 0, high-salinity fluid SI can be divided into four stages: initial imbibition stage, drainage stage, secondary imbibition stage and stationary stage; when S w = 0, there is no drainage stage of high-salinity fluid SI; when S w ≠ 0 or S w = 0, low-salinity fluid SI can be called the “osmosis-enhanced SI”; and we have found that “newly formed pores or microfractures” as well as reducing salinity can promote SI. This article presents a systematic study of SI of shale oil reservoirs under the influence of osmosis, which provide useful information for reservoir numerical simulation and development program design.

Abstract Background Erythropoietin is a glycoprotein that mainly regulates erythropoiesis. In patients with chronic renal failure with anemia, darbepoetin alfa can stimulate erythropoiesis, correct anemia, and maintain hemoglobin levels. This study was designed to demonstrate the efficacy and safety of darbepoetin alfa injections as being not inferior to epoetin alfa injections (Recombinant Human Erythropoietin injection, rHuEPO) when maintaining hemoglobin (Hb) levels within the target range (10.0–12.0 g/dL) for the treatment of renal anemia. Methods Ninety‐five patients were enrolled in this study from April 15, 2013 to April 10, 2014 at 25 sites. In this study, patients (n = 95) aged 18–70 years were randomized into a once per week intravenous darbepoetin alfa group (n = 56) and a twice or three times per week intravenous epoetin alfa group (n = 39) for 28 weeks, who had anemia with hemoglobin levels between 6 g/dL and 10 g/dL due to chronic kidney disease (CKD) and were undergoing hemodialysis or hemofiltration with ESA‐naive (erythropoiesis stimulating agent‐naive). The primary efficacy profile was the mean Hb level (the non‐inferiority margin was −1.0 g/dL, week 21–28); the secondary efficacy profiles were the Hb increase rate (week 0–4), the target Hb achievement cumulative rate and time, the change trends of the Hb levels, and the target Hb maintenance ratio. Adverse events (AEs) were observed and compared, and the efficacy and safety were analyzed between the two treatment groups. Additionally, the frequencies of dose adjustments between the darbepoetin alfa and epoetin alfa groups were compared during the treatment period. SAS® software version 9.2 was used to perform all statistical analyses. Descriptive statistics were used for all efficacy, safety, and demographic variable analyses, including for the primary efficacy indicators. Results The mean Hb level was 11.3 g/dL in the darbepoetin alfa group and 10.7 g/dL in the epoetin alfa group, respectively; the difference of the lower limits of the 95% confidence intervals (CI) between the two groups was 0.1 g/dL (>−1.0 g/dL), and non‐inferiority was proven; the Hb levels started to increase in the first four weeks at a similar increase rate; no obvious differences were observed between the groups in the target Hb achievement cumulative rates, and the Hb levels as well as the target Hb level maintenance rate changed over time. The incidence of AEs was 62.5% in the darbepoetin alfa group and 76.9% in the epoetin alfa group. All the adverse events observed in the study were those commonly associated with hemodialysis. Conclusion Darbepoetin alfa intravenously once per week can effectively increase Hb levels and maintain the target Hb levels well, which makes it not inferior to epoetin alfa intravenously twice or three times per week. Darbepoetin alfa shows an efficacy and safety comparable to epoetin alfa for the treatment of renal anemia.

This article focused on the study of pore structure characteristics of Songhe and Linhua coal samples based on mercury injection experiments and high-pressure isothermal adsorption experiments. The results show that the pore structure of coal samples in the two mining areas is obviously different under the influence of metamorphic degree. The pores of Songhe mine coal samples, which are characteristic of middle-rank coal reserves, are predominantly open cylindrical pores with good connectivity to medium-to-large pores but poor absorption capacity. The tiny and medium pores of Linhua coal samples, which are characteristic of high-level coal reserves, have poor connectivity, dominated by conical pores with mostly closed and semi-closed pores. The pore size distribution of the middle-rank coal sample is multi-peaked, with better developed pore sizes, while the pore size distribution of the Linhua coal sample is bi-peaked, with micro and small pores developed. The pore fractal shape of high-rank coal reserves is higher than that of middle-rank coal reserves, and the complexity of permeable pore space and diffusive pore space of high-order coal reservoirs is higher than that of middle-order coal reservoirs.

The coal facies and their effects on the coal pore characteristics of the Late Permian Longtan Formation, western Guizhou, were studied, using diverse experiments of macerals and minerals compositions, vitrinite reflectance, and pore characteristics. The results show that five coal facies exist in studied samples, and they are shallow-water covered forest peat swamp facies, moist forest peat swamp facies, dry forest peat swamp facies, low peat swamp facies, and wet land herbaceous peat swamp facies. Among them, the moist forest peat swamp facies accounts for the largest proportion, followed by the shallow-water covered forest peat swamp and dry forest peat swamp facies. The order of pore development degree is identical with the order of moist forest peat swamp facies coal > shallow-water covered forest peat swamp facies coal > dry forest peat swamp facies coal. In contrast to shallow-water covered forest peat swamp facies and dry forest peat swamp facies samples, moist forest peat swamp facies samples have higher porosity and larger pore size. Coal facies play an important role in controlling the pore structure of coal reservoir, which have more effect on pore size distribution than coal rank for the samples in this study.

Energy security and the reduction of greenhouse gases such as carbon dioxide are two major crises facing the world today. Using carbon dioxide to develop unconventional oil and gas resources is a positive way to reduce greenhouse gas emissions, which can significantly alleviate global energy security issues. This study systematically introduces the prerequisites for CO2 to extract crude oil and CO2 to be safely and effectively stored. Under high temperature and high pressure, the rock properties of deep reservoirs are completely different from those of atmospheric conditions in the two-phase porous media environment of crude oil and high salinity formation water. The research progress on the phase behavior, mutual solubility, CO2 storage potential and mechanism between supercritical CO2 and crude oil, formation water and reservoir are reviewed in detail. In addition, CO2 leakage will inevitably occur during long-term geological storage, the proper estimation and evaluation of the risk and establishment of corresponding sealing methods are the way forward for CO2 geological storage. By systematically elaborating the nature, advantages and disadvantages of fluid–fluid, fluid–solid interaction and geological integrity destruction mechanism, the directions in which several key problems should be solved were pointed out.

The effect of water imbibition on characteristics of coalbed methane reservoirs, such as permeability, gas occurrence state, and gas production, is controversial. According to the mechanism of imbibition, gas and water distribution in blind pores is reconfigured during the fracturing process. Therefore, a new comprehensive model of pore pressure and permeability, based on the perfect gas equation and the weighted superposition of viscous flow and Knudsen diffusion, was established for micro- and nanoscale blind pores during water drainage. Using the numerical simulation module in the Harmony software, the effects of imbibition on coal pore pressure, permeability, and gas production were analyzed. The results showed that (1) water imbibition can increase pore pressure and reduce permeability, and (2) water imbibition is not always deleterious to gas production and estimated ultimate reserve (EUR), when the imbibition is constant, the thicker water film is deleterious to coalbed methane wells; when the thickness of water film is constant, more imbibition is beneficial to gas production and EUR. This research is beneficial to optimize the operation of well shut-ins after fracturing and provides methods for optimizing key parameters of gas reservoirs and insights into understanding the production mechanism of coalbed methane wells.

The underlying mechanism of shale gas migration behavior is of great importance to understanding the flow behavior and the prediction of shale gas flux. The slippage of the methane molecules on the surface is generally emphasized in nanopores in most predicted methods currently. In this work, we use molecular dynamic (MD) simulations to study the methane flow behavior in organic (graphene) and inorganic (quartz) nanopores with various pore size. It is observed that the slippage is obvious only on the graphene nanopores and disappeared on the quartz surface. Compared with the traditional Navier-Stokes equation combined with the no-slip boundary, the enhancement of the gas flux is nonnegligible in the graphene nanopores and could be neglected in the quartz nanopores. In addition, the flux contribution ratios of the adsorption layer, Knudsen layer, and the bulk gas are analyzed. In quartz nanopores, the contributions of the adsorption layer and the Knudsen layer are slight when the pore size is larger than 10 nm. It is also noted that even if the Knudsen number is the same, the flow mode may be various with the effect of the pore surface type. Our work should give molecular insights into gas migration mechanisms in organic and inorganic nanopores and provide important reference to the prediction of the gas flow in various types of shale nanopores.

The difficulty of deploying remaining oil from unconventional reservoirs and the increasing CO2 emissions has prompted researchers to delve into carbon emissions through Carbon Capture, Utilization, and Storage (CCUS) technologies. Under the confinement of nanopore in unconventional formation, CO2 and hydrocarbon molecules show different density distribution from in the bulk phase, which leads to a unique phase state and interface behavior that affects fluid migration. At the same time, mineral reactions, asphaltene deposition, and CO2 pressurization will cause the change of porous media geometry, which will affect the multiphase flow. This review highlights the physical and chemical effects of CO2 injection into unconventional reservoirs containing a large number of micro-nanopores. The interactions between CO2 and in situ fluids and the resulting unique fluid phase behavior, gas-liquid equilibrium calculation, CO2 adsorption/desorption, interfacial tension, and minimum miscible pressure (MMP) are reviewed. The pore structure changes and stress distribution caused by the interactions between CO2, in situ fluids, and rock surface are discussed. The experimental and theoretical approaches of these fluid-fluid and fluid-solid reactions are summarized. Besides, deficiencies in the application and safety assessment of CCUS in unconventional reservoirs are described, which will help improve the design and operation of CCUS.

The fractal geometry, anisotropy, discontinuity, and non-Darcy flow of tight reservoirs exert a significant effect on well production performance. In this study, the reservoir fractal geometry is represented by exponential functions on the basis of microseismic data, while the discontinuity of the fractures is presented as a nonequilibrium effect. The impact of the nonequilibrium effect and the low velocity non-Darcy flow on the temporal scale of the wellbore pressure is predicted herein. Results showed that the time scale analysis accurately simulates gas flow in a tight reservoir. The wellbore pressure gradually increases, whereas the pressure in the matrix lags when the nonequilibrium effect is considered. The wellbore pressure is affected in the early period by the nonequilibrium effect. However, at the later stage, the pressure in the matrix is mainly affected by the non-Darcy flow. When the non-Darcy flow is dominant, the pores without gas flowing through are better presented.

Shale reservoirs are characterized by low porosity and low permeability, and volume fracturing of horizontal wells is a key technology for the benefits development of shale oil resources. The results from laboratory and field tests show that the backflow rate of fracturing fluid is less than 50%, and the storage amount of fracturing fluid after large-scale hydraulic fracturing is positively correlated with the output of single well. The recovery of crude oil is greatly improved by means of shut-in and imbibition, therefore attracting increasing attention from researchers. In this review, we summarize the recent advances in the migration mechanisms and stimulation mechanisms of horizontal well high pressure forced soaking technology in the reservoirs. However, due to the diversity of shale mineral composition and the complexity of crude oil composition, the stimulation mechanism and effect of this technology are not clear in shale reservoir. Therefore, the mechanism of enhanced oil recovery by imbibition and the movable lower limit of imbibition cannot be characterized quantitatively. It is necessary to solve fragmentation research in the full-period fluid transport mechanisms in the follow-up research.

A fracture will be initiated and propagated along the direction of maximum horizontal stress in fracturing treatment; however, in refracturing stimulation, the new fracture may be initiated and propagated along a different direction from the initial one. This is defined as a fracture reorientation. It is difficult to predict fracture reorientation due to the variation of formation properties after long-term production. To verify the existence of fracture reorientation and analyze its influencing factors in multiple fracturing treatment, experimental and numerical simulations are presented in this paper. Firstly, multiple fracturing stimulation is carried out with a self-assembled large true triaxial apparatus, and the fracture reorientation is successfully induced by changing the injection pressure and initial stresses in multiple fracturing processes. Then, numerical coupled hydromechanical modeling of the actual field production and injection well pattern is performed. In particular, the stress reversal region, which indicates the distance of fracture reorientation, and the factors that influence the reorientation are analyzed. The laboratory experiment and numerical simulation results show that the fracture reoriented angle obtained can be perpendicular to the initial fracture. Stress field and formation pressure are the two main factors that influence the fracture reorientation. With higher pressure differences and lower initial horizontal stress differences, the area in which it is possible to initiate reoriented fracture will be larger. The fractures of wells in the early production stage are hard to reorient due to the high formation and borehole pressure difference, and the fracture reorientation area will be expanded until the pressure difference is low to a certain value. This research result can guide oilfield stimulation treatments.

Based on the analysis of the typical Ordos well groups, this study began with the accurate characterization of the fracture geometry by adopting advanced laboratory experiment methods and monitoring techniques. Then, with the integration of fracture geometry characterization and in situ stress distributions, fracture optimizations of the target wells were performed through numerical simulations methods. Finally, this study established a sweet spot prediction and identification method for long horizontal shale oil wells and constructed a set of optimization design methods for multistage hydraulic fracturing. This investigation revealed that the hydraulic fractures in Chang-7 terrestrial shale oil reservoirs exhibited the belt pattern, and the primary fractures generated the secondary fractures, which activated the natural fractures and induced shear failure. Macroscopic fractures were found to be perpendicular to the direction of the minimum principal stress. Secondary fractures and activated natural fractures were distributed around the primary fracture in the form of fracture types I and II. Multicluster perforation optimization techniques, which were based on shale reservoir classification and evaluation, and aimed at activating multiclusters and determining fracture sweet spots, were developed. These were successfully applied to the field operation and achieved production enhancement performance.

CO2-alternating-water injection is an effective way of enhancing recovery for low-permeability oil reservoirs. The injection process is one of the essential issues that are facing severe challenges because of the low permeability and poor pore space connectivity. Previous researchers mentioned that water injection ability could be decreased by around 20% after the CO2-flooding; hence, it is necessary to quantify the water injectivity variation during an alternated injection process. In this paper, a CO2 convection-diffusion model is established based on the seepage law of CO2 and dissipation effect. The relationship between the width of miscible flooding and injection time is defined. Besides, an equivalent resistance method is introduced for developing a capillary bundle model for featuring an unequal diameter for CO2 water vapor alternate flooding. CO2-oil and CO2-water interactions are analyzed using the new model. The effects of oil viscosity, pore throat ratio, CO2 slug size, and equivalent permeability of the capillary bundle on water injection are analyzed. The result indicates that water injection ability increases with the rise of CO2 slug size and equivalent permeability of the capillary bundle and decreases with the increase of viscosity and pore throat ratio.

In all the existing apparent permeability calculation models used for shale gas, the effect of surface diffusion of adsorbed gas is neglected and shale gas is assumed to be in an ideal state, so the calculation results may not reflect the real situations. In this paper, a new apparent permeability model suitable for the shale gas of real state was developed by seepage mechanics method. In this model, the influential factors (e.g. the viscous flow and Knudsen diffusion of free gas and the surface diffusion of adsorbed gas) are taken into account to present the real flowing situations of shale gas in nanopores. Then, the accuracy of this new apparent permeability model was verified by comparing its calculation results with the experimental data. Finally, all factors influencing the apparent permeability of shale gas were analyzed in this new model. It is shown that the apparent permeability of shale gas is most affected by pressure and pore radius, and less by relative molecular mass and blockage coefficient. Langmuir maximum adsorption capacity, Langmuir pressure and isothermal adsorption heat mainly affect the fraction of permeability contributed by surface diffusion. Besides, the effects of each factor on apparent permeability and permeability fraction under low pressure are different from those under high pressure. Under low pressure, the effects of temperature and pore radius on apparent permeability are more obvious, and the effects of temperature, pore radius, Langmuir maximum adsorption capacity, Langmuir pressure and isothermal adsorption heat on the fraction of permeability are also more obvious. Finally, when the pressure is low and the pore radius is small, the surface diffusion is dominant. When the pressure is high and the pore radius is large, the viscous flow is dominant. In the case of small pore radius or low pressure, the surface diffusion shall not be neglected. Keywords: Real state, Shale gas, Apparent permeability, Computation model, Viscous flow, Knudsen diffusion, Adsorption, Surface diffusion, Fraction of permeability

The channel fracturing technique has been proven to provide much higher conductive fracture networks by placing discontinuously proppant inside fracture packs. Despite the great success of this new fracturing technique, there is still a lack of models and methods to characterize non-uniform placement of fracture proppant and heterogeneous permeability distribution within stimulated-reservoir-volume (SRV). In this article, a dual-porosity model is coupled with the tri-linear flow model to quantify the production performance of channel fractured horizontal wells. As a consequence of channel fracturing, the non-uniform distribution of fracture networks, and the heterogeneities of both matrix/fracture porosity and permeability are characterized using fractal theory. By implementing the Bessel Function and Laplace transform techniques, analytical solutions are derived by integrating fluid flow across primary hydraulic fractures, SRV and unstimulated reservoir matrices. Through quantitative comparisons of well bottom-hole pressure history, a synthetic fine-grid numerical simulation example is implemented to verify the accuracy of analytical solutions. Sensitivity analysis of fractal dimension, fractal connectivity-index and primary fracture conductivity is carried out to quantify the temporal and spatial consequences of channel fracturing on both reservoir/facture heterogeneity and well productivity throughout well life.

Abstract This paper presents the theory and application to modify the conventional simulator to describe the effects of gas adsorption and gas slippage flow in shale gas. Because of the local desorption of gas and the assumptions of gas desorption instantaneously with the decrease in pore pressure, we define one fictitious immobile “pseudo” oil with dissolved gas. The dissolved gas–oil ratio is calculated from the Langmuir adsorption isotherm constants and shale gas properties. Additional modifications required in the input data are the porosity and relative permeability curves to account for the existence of “pseudo” oil. The input rock table considers the changes of rock permeability versus pressure to describe the gas slippage flow effects. In addition, dual-porosity dual-permeability models coupled with local grid refinement method are used to distinguish the impacts of natural fractures and hydraulic fractures on shale gas production with the comparison of vertical well, fractured vertical well, horizontal well, and multistage fractured horizontal well production. This proposed simulation approach shows enough accuracy and outstanding time efficiency. Results show that ignoring gas desorption and slippage flow effects would bring significant error in shale gas simulation The existence of natural fractures also imposes great effects on the productivity of shale gas.

In this paper, a slip length model is proposed to analyze the enhanced flow based on the Hagen–Poiseuille equation. The model considers the multimechanisms including wall-water molecular interactions, pore dimensions, fractal roughness, and temperature. The increasing wall-water interactions result in the greater slip length and flow enhancement factor. The increased temperature enhances the kinetic energy of water molecules that leads to great surface diffusion coefficient and small work of adhesion. The wall roughness can decrease the slip length and flow enhancement factor in hydrophilic nanopores. This work studies the effects of multimechanisms on slip length and flow enhancement factor theoretically, which can accurately describe the liquid flow in nanopores.

Aimed at enhancing the oil recovery of tight reservoirs, the mechanism of hot water flooding was studied in this paper. Experiments were conducted to investigate the influence of hot water injection on oil properties, and the interaction between rock and fluid, petrophysical property of the reservoirs. Results show that with the injected water temperature increasing, the oil/water viscosity ratio falls slightly in a tight reservoir which has little effect on oil recovery. Further it shows that the volume factor of oil increases significantly which can increase the formation energy and thus raise the formation pressure. At the same time, oil/water interfacial tension decreases slightly which has a positive effect on production though the reduction is not obvious. Meanwhile, the irreducible water saturation and the residual oil saturation are both reduced, the common percolation area of two phases is widened and the general shape of the curve improves. The threshold pressure gradient that crude oil starts to flow also decreases. It relates the power function to the temperature, which means it will be easier for oil production and water injection. Further the pore characteristics of reservoir rocks improves which leads to better water displacement. Based on the experimental results and influence of temperature on different aspects of hot water injection, the flow velocity expression of two-phase of oil and water after hot water injection in tight reservoirs is obtained.

Background: Single nucleotide polymorphisms (SNPs) in the DNA repair genes are suspected to be related to the survival of lung cancer patients due to their possible influence on DNA repair capacity (DRC). However, the study results are inconsistent. Methods: A follow-up study of 610 non-small cell lung cancer (NSCLC) patients was conducted to investigate genetic polymorphisms associated with the DNA repair genes in relation to NSCLC survival; 6 SNPs were genotyped, including XRCC1 (rs25487 G>A), hOGG1 (rs1052133 C>G), MUTYH (rs3219489 G>C), XPA (rs1800975 G>A), ERCC2 (rs1799793 G>A) and XRCC3 (rs861539 C>T). Kaplan-Meier survival curve and Cox proportional hazards regression analyses were performed. SNP-SNP interaction was also examined using the survival tree analysis. Results: Advanced disease stage and older age at diagnosis were associated with poor prognosis of NSCLC. Patients with the variant ‘G' allele of hOGG1 rs1052133 had poor overall survival compared with those with the homozygous wild ‘CC' genotype, especially in female patients, adenocarcinoma histology, early stage, light smokers and without family history of cancer. For never smoking female lung cancer patients, individuals carrying homozygous variant ‘AA' genotype of XPA had shorter survival time compared to those with wild ‘G' alleles. Furthermore, females carrying homozygous variant XPA and hOGG1 genotypes simultaneously had 2.78-fold increased risk for death. Among all 6 polymorphisms, the homozygous variant ‘AA' of XPA carriers had poor prognosis compared to the carriers of wild ‘G' alleles of XPA together with other base excision repair (BER) polymorphisms. Conclusions: Besides disease stage and age, the study found DNA repair gene polymorphisms were associated with lung cancer survival.

There are multiporosity media in tight oil reservoirs after stimulated reservoir volume (SRV) fracturing. Moreover, multiscale flowing states exist throughout the development process. The fluid flowing characteristic is different from that of conventional reservoirs. In terms of those attributes of tight oil reservoirs, considering the flowing feature of the dual-porosity property and the fracture network system based on the discrete-fracture model (DFM), a mathematical flow model of an SRV-fractured horizontal well with multiporosity and multipermeability media was established. The numerical solution was solved by the finite element method and verified by a comparison with the analytical solution and field data. The differences of flow regimes between triple-porosity, dual-permeability (TPDP) and triple-porosity, triple-permeability (TPTP) models were identified. Moreover, the productivity contribution degree of multimedium was analyzed. The results showed that for the multiporosity flowing states, the well bottomhole pressure drop became slower, the linear flow no longer arose, and the pressure wave arrived quickly at the closed reservoir boundary. The contribution ratio of the matrix system, natural fracture system, and network fracture system during SRV-fractured horizontal well production were 7.85%, 43.67%, and 48.48%, respectively in the first year, 14.60%, 49.23%, and 36.17%, respectively in the fifth year, and 20.49%, 46.79%, and 32.72%, respectively in the 10th year. This study provides a theoretical contribution to a better understanding of multiscale flow mechanisms in unconventional reservoirs.

Abstract: In recent years, multi-stage hydraulic fracturing technologies have greatly facilitated the development of unconventional oil and gas resources. However, a quantitative description of the “complexity” of the fracture network created by the hydraulic fracturing is confronted with many unsolved challenges. Given the multiple scales and heterogeneity of the fracture system, this study proposes a “bifurcated fractal” model to quantitatively describe the distribution of induced hydraulic fracture networks. The construction theory is employed to generate hierarchical fracture patterns as a scaled numerical model. With the implementation of discrete fractal-fracture network modeling (DFFN), fluid flow characteristics in bifurcated fractal fracture networks are characterized. The effects of bifurcated fracture length, bifurcated tendency, and number of bifurcation stages are examined. A field example of the fractured horizontal well is introduced to calibrate the accuracy of the flow model. The proposed model can provide a more realistic representation of complex fracture networks around a fractured horizontal well, and offer the way to quantify the “complexity” of the fracture network in shale reservoirs. The simulation results indicate that the geometry of the bifurcated fractal fracture network model has a significant impact on production performance in the tight reservoir, and enhancing connectivity of each bifurcate fracture is the key to improve the stimulation performance. In practice, this work provides a novel and efficient workflow for complex fracture characterization and production prediction in naturally-fractured reservoirs of multi-stage fractured horizontal wells.

A turning machine tool is a kind of new type of machine tool that is equipped with more than one spindle and turret. The distinctive simultaneous and parallel processing abilities of turning machine tool increase the complexity of process planning. The operations would not only be sequenced and satisfy precedence constraints, but also should be scheduled with multiple objectives such as minimizing machining cost, maximizing utilization of turning machine tool, and so on. To solve this problem, a hybrid genetic algorithm was proposed to generate optimal process plans based on a mixed 0-1 integer programming model. An operation precedence graph is used to represent precedence constraints and help generate a feasible initial population of hybrid genetic algorithm. Encoding strategy based on data structure was developed to represent process plans digitally in order to form the solution space. In addition, a local search approach for optimizing the assignments of available turrets would be added to incorporate scheduling with process planning. A real-world case is used to prove that the proposed approach could avoid infeasible solutions and effectively generate a global optimal process plan.

Stimulated reservoir volume (SRV) fracturing in tight oil reservoirs often induces complex fracture-network growth, which has a fundamentally different formation mechanism from traditional planar bi-winged fracturing. To reveal the mechanism of fracture network propagation, this paper employs a modified displacement discontinuity method (DDM), mechanical mechanism analysis and initiation and propagation criteria for the theoretical model of fracture network propagation and its derivation. A reasonable solution of the theoretical model for a tight oil reservoir is obtained and verified by a numerical discrete method. Through theoretical calculation and computer programming, the variation rules of formation stress fields, hydraulic fracture propagation patterns (FPP) and branch fracture propagation angles and pressures are analyzed. The results show that during the process of fracture propagation, the initial orientation of the principal stress deflects, and the stress fields at the fracture tips change dramatically in the region surrounding the fracture. Whether the ideal fracture network can be produced depends on the geological conditions and on the engineering treatments. This study has both theoretical significance and practical application value by contributing to a better understanding of fracture network propagation mechanisms in unconventional oil/gas reservoirs and to the improvement of the science and design efficiency of reservoir fracturing.

ObjectivesLung adenocarcinoma is considered a unique disease for Asian female non-smokers. We investigated whether plasma microRNA (miRNA) expression profiles are different by the EGFR status and are associated with survival outcomes of the patients.MethodsUsing real-time RT-PCR, we analyzed the expression of 20 miRNAs in the plasma of 105 female patients with lung adenocarcinoma. Kaplan-Meier survival analysis and Cox proportional hazards regression were performed to determine the association between miRNA expression and overall survival. Time dependent receiver operating characteristic (ROC) analysis was also performed.ResultsIn the 20 miRNAs, miR-122 were found differently expressed between wild and mutant EGFR carriers (P=0.018). Advanced disease stage and tumor metastasis were independently associated with poor prognosis of patients with lung adenocarcinoma (P=0.010 and 1.0×10(-4)). Plasma levels of miR-195 and miR-122 expression were also associated with overall survival in the patients, especially in those with advanced stage (HR=0.23, 95%CI:0.07-0.84; and HR=0.22, 95%CI:0.06-0.77) and EGFR mutation (HR=0.27, 95%CI:0.08-0.96; and HR=0.23, 95%CI=0.06-0.81). Moreover, a model including miR-195, miR-122 may predict survival outcomes of female patients with lung adenocarcinoma (AUC=0.707).ConclusionsCirculating miR-195 and miR-122 may have prognostic values in predicting the overall survival as well as predicting EGFR mutation status in non-smoking female patients with lung adenocarcinoma. Measuring plasma levels of miR-195 and miR-122 may especially be useful in EGFR mutant patients with lung adenocarcinoma.

Subsequent CO2 injection can enhance oil recovery and achieve carbon sequestration in shale reservoirs, which is crucial for energy sustainability and environmental protection. However, for continental sedimentary shale oil, the development process must consider the multiscale matrix-fracture structure and the impact of heterogeneous wettability on fluid-solid interactions. Moreover, the mechanisms of CO2 miscibility and interfacial behavior in post-fracturing reservoirs remain unclear. In this study, a laminated shale micro-model with fracture based on scanning electron microscopy observations was designed, and the process of fracturing fluid flowback and subsequent CO2 huff-n-puff were simulated. Results showed that forced imbibition primarily affects limestone layers, while spontaneous imbibition affects mudstone layers, contributing 89.3% and 10.7% to the affected area, respectively. The oil recovery mechanism of CO2 is mainly influenced by pressure, transfer from displacement-carry at low pressure to dissolution-extraction, and eventually to diffusion-extraction in the miscible state. Additionally, before reaching miscibility, Taylor dispersion, Kelvin-Helmholtz instability, Rayleigh-Taylor instability, and Marangoni effects occur at the oil-CO2 interface, leading to interfacial turbulent instability. Lastly, water huff-n-puff produces membrane and isolated droplet residual oil, while immiscible CO2 breaks cluster residual oil into columnar residual oil. Miscible CO2 enhances the recovery of various residual oils, improving oil recovery and facilitating CO2 storage. This study provides insights for post-fracturing CO2 huff-n-puff development of continental sedimentary shale oil and CO2 sequestration, promoting energy utilization and environmental improvement. [ABSTRACT FROM AUTHOR]

Class III tight oil reservoirs have low porosity and permeability, which are often responsible for low production rates and limited recovery. Extensive repeated fracturing is a well-known technique to fix some of these issues. With such methods, existing fractures are refractured, and/or new fractures are created to facilitate communication with natural fractures. This study explored how different refracturing methods affect horizontal well fracture networks, with a special focus on morphology and related fluid flow changes. In particular, the study relied on the unconventional fracture model (UFM). The evolution of fracture morphology and flow field after the initial fracturing were analyzed accordingly. The simulation results indicated that increased formation energy and reduced reservoir stress differences can promote fracture expansion. It was shown that the length of the fracture network, the width of the fracture network, and the complexity of the fracture can be improved, the oil drainage area can be increased, the distance of oil and gas seepage can be reduced, and the production of a single well can be significantly increased. [ABSTRACT FROM AUTHOR]

Ultra-low permeability reservoirs are characterized by small pore throats and poor physical properties, which are at the root of well-known problems related to injection and production. In this study, a gas injection flooding approach is analyzed in the framework of numerical simulations. In particular, the sequence and timing of fracture channeling and the related impact on production are considered for horizontal wells with different fracture morphologies. Useful data and information are provided about the regulation of gas channeling and possible strategies to delay gas channeling and optimize the gas injection volume and fracture parameters. It is shown that in order to mitigate gas channeling and ensure high production, fracture length on the sides can be controlled and longer fractures can be created in the middle by which full gas flooding is obtained at the fracture location in the middle of the horizontal well. A Differential Evolution (DE) algorithm is provided by which the gas injection volume and the fracture parameters of gas injection flooding can be optimized. It is shown that an improved oil recovery factor as high as 6% can be obtained. [ABSTRACT FROM AUTHOR]