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The complexities of deep shale reservoirs are expressed in terms of multi-scale pore structure, abundant micro-fractures, strong stress dependence and multiple gas transport mechanisms. The current macro-scale numerical simulation models have not fully considered the influence of multi-scale pore-fracture structure on gas transport in deep shale reservoirs. In this work, we propose a general fractal-based multi-scale quin-medium model for gas transport in deep shale reservoirs. The quin-medium is composed of organic matter, inorganic matter, micro-fracture medium, induced hydraulic fracture network and hydraulic fracture. The shale matrix is modeled by multiple interacting continua (MINC) with intersected organic matter, inorganic matter and micro-fracture medium. Organic matter is distributed at the center of MINC while the micro-fracture medium is embedded into inorganic matter with layered distribution. The organic/inorganic pore structure and micro-fracture are characterized by fractal geometry, respectively. The apparent gas permeability in each medium is derived considering gas slippage and stress-dependence while the adsorbed gas surface diffusion and Langmuir volumetric strain are additionally considered in organic matter. The apparent gas permeability models are further substituted into the quin-medium continuity equations and the hydraulic fracture is described by an embedded discrete fracture model. The influences of pore structure fractal parameters, gas transport mechanisms and stress dependence on deep shale gas productivity are analyzed in detail. We found that the influence of stress dependence on deep shale gas productivity is more pronounced than the gas transport mechanism. Furthermore, the pore structure fractal parameter of inorganic matter has a more notable influence on deep shale gas productivity than that of organic matter and micro-fracture medium. [ABSTRACT FROM AUTHOR]

The challenges of modeling shale oil transport are numerous and include strong solid-fluid interactions, fluid rheology, the multi-scale nature of the pore structure problem, and the different pore types involved. Until now, theoretical studies have not fully considered shale oil transport mechanisms and multi-scale pore structure properties. In this study, we propose a fractal-based oil transport model with uncertainty reduction for a multi-scale shale pore system. The fractal properties of the shale pore system are obtained using high-resolution scanning electron microscope (SEM) imaging combined with laboratory core sample gas permeability measurements to reduce the model uncertainty. This fractal-based oil transport model accounts for boundary slippage, fluid rheology, the adsorption layer, and different pore types. We further pinpoint the effects of the fractal properties (pore fractal dimension, tortuosity fractal dimension), the shale pore properties (pore type, pore size, total organic carbon in volume), and the fluid properties (yield stress, liquid slippage, adsorption layer) on the shale oil permeability and mobile oil saturation using the proposed model. The results reveal that the size of the inorganic pores has the largest influence on the shale oil transport properties, followed by the yield stress, tortuosity fractal dimension, and the fractal dimension of the inorganic pores. [ABSTRACT FROM AUTHOR]

Conventional reservoir drill-in fluids used for drilling reservoirs in Weizhou Oilfield encounter rheological problems that result in technical problems such as hole-cleaning in openhole horizontal intervals. Hence, novel drill-in fluid was developed by optimizing the additive quantity and particle size distribution. Lab tests showed that novel drill-in fluids boast high low shearing rate viscosity, and provide promising cutting, carrying, and suspension capabilities. Furthermore, the novel drill-in fluids performed well in reservoir protection, with a permeability recovery rate of more than 90%. The novel drill-in fluids also have high inhibition capabilities with a linear expansion rate of mud shale as low as 10%, with a rolling recovery rate of up to 96.48%. Field application results showed no pipe-stuck was encountered during tripping in the horizontal interval when using the novel drill-in fluid. Moreover, by using the novel drill-in fluids, skin factor was reduced from 20.0 to −3.0, and daily oil production was double what was expected. It was concluded that novel drill-in fluids meets the demand of horizontal drilling intervals in Weizhou Oilfield and improves hole-cleaning and reservoir protection in the horizontal well. [ABSTRACT FROM AUTHOR]

Rate of penetration (ROP) prediction is critical for the optimization of drilling parameters and ROP improvement during drilling. However, it is still challenging to accurately predict ROP based on traditional empirical formula methods. This is usually the case for the development of the Wushi 17-2 oilfield block in the South China Sea. The Liushagang Formation is complex and the ROP is relatively low and difficult to increase. Ordinary data-driven ROP prediction models are not applicable because they do not take into account the complexity of formation conditions. In this work, we characterize the formation with acoustic transit time and build a data-driven ROP prediction model based on a deep neural network approach. By using the exploratory well data of the Wushi 17-2 oilfield for training and testing, the matching degree of the established model with the real data can reach 82%. In addition, we have developed a drilling parameter optimization process based on the ROP prediction model to improve ROP. Through on-site simulation, we found that the process can well meet the construction requirements. The established models and process flow are also applicable to the development of other formations and fields. [ABSTRACT FROM AUTHOR]

The transient response of a cylindrical casing-cement structure in a poroelastic stratum under dynamic radial tractions is one of the significant issues during the analysis of downhole operations and the selection of safe material. Based on the Biot theory and general elastic mechanics, this paper gives a set of exact solutions for radial displacement, stresses for the casing-cement system and the pore pressure of the infinite surrounding poroelastic stratum in the Laplace transform space. Solutions are presented for three different types of transient radial loadings acting on the surface of casing, i.e., suddenly applied constant load, gradually applied step load and triangular pulse load. Time domain solutions are obtained using a reliable numerical method of inverse Laplace transforms. A detailed parametric study about the transient response is presented both at the casing-cement interface and the cement-stratum interface, and the distributions of the pore pressure and the effective stresses in the stratum are also examined. Copyright © 2017 John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

• Nanoindentation (Ni) was used to characterize cement-elastomer composites. • Big data Ni (BDNi) can characterize cross-scale mechanical properties. • Emulsion and particulate elastomers play different roles in microstructure. • Hematite can counteract the influence of elastomers. • Multiple functioning phases contribute to the overall behavior of composites. Intensive big data nanoindentation (BDNi) characterization was performed to reveal the cross-scale mechanical properties of, and hence distinguish the different phases in, inorganic–organic hybrid oilwell cement-elastomer composites, hydrothermally cured at 160 °C and 20 MPa for 28 days. Totally-three emulsified and particulate elastomers, including styrene-butadiene latex (SBL) emulsion (6, 12, and 14 wt.%), polypropylene (PP) powder (12 wt.%), and nitrile rubber (NR) powder (6 wt.%), and a weighting agent, hematite (50 wt.%), were used as additives to finely adjust the mechanical properties and microstructure of the hybrid composites, which were respectively examined by the BDNi and mercury intrusion porosimetry and scanning electron microscopy. BDNi data were statistically deconvoluted by the Gaussian mixture modeling (GMM) to discern mechanically distinct phases and their Young's moduli and hardness at the micro/nano scale and the bulk composites' properties at the macro scale. Results show that the SBL emulsion can be more homogeneously dispersed into the cement matrix, due to its emulsified soft consistency and hydrophilicity, resulting in the formation of soft coatings on, and softer infills intermixed with, the cement hydration products (CHPs). In contrast, the two hydrophobic, inert, particulate elastomers, PP and NR powders, only act as isolated soft inclusions embedded in the hydrated cement matrix. The NR melts at high temperatures and permeates into the pores of the cement matrix, leading to the formation of complex intervened micromorphology and hence functions better than the PP. All elastomers can effectively reduce the composites' Young's moduli: with increasing the elastomer contents, while the modulus of a BDNi-identified major CHP phase decreases from 20.9 to 11.3 GPa, the bulk composites' counterpart from 17.3 to 10.7 GPa. The BDNi enables the identification of multiple mechanically distinct phases in the hybrid composites and quantification of the property changes of these phases. [ABSTRACT FROM AUTHOR]

Wellbore instability resulting from deep mudstone hydration severely restricts the development of oil and gas resources from deep reservoir in western China. Accurate evaluation of drilling fluid inhibition properties plays an important role in selecting drilling fluid that can control deep mudstone hydration and then sustain wellbore stability. The previous evaluations are conducted by qualitative analysis and cannot consider the influence of complex hydration conditions of deep mudstone (high temperature, high pressure and flushing action). The study proposes a quantitative method to evaluate drilling fluid's inhibition property for deep mudstone under natural drilling conditions. In this method, the cohesive strength of mudstone after hydration is adopted as the inhibition index of the tested drilling fluid. An experimental platform containing a newly designed HPHT (High pressure and high temperature) hydration experiment apparatus and mechanics characterization of mudstone after hydration based on scratch test is proposed to obtain the current inhibition index of tested drilling fluid under deep well drilling environments. Based on the mechanical–chemical wellbore stability model considering strength weakening characteristics of deep mudstone after hydration, a cross-correlation between drilling fluid density (collapse pressure) and required inhibition index (cohesive strength) for deep mudstone is provided as the quantitative evaluation criterion. Once the density of tested mud is known, one can confirm whether the inhibition property of tested mud is sufficient. In this study, the JDK mudstone of a K block in western China is selected as the application object of the proposed evaluation method. Firstly, the evaluation chart, which can demonstrate the required inhibition indexes of the tested fluids quantitatively with various densities for JDK mudstone, is constructed. Furthermore, the experimental evaluations of inhibition indexes of drilling fluids taken from two wells in K block are conducted under ambient and deep-well drilling conditions, respectively. In order to show the validity and advantage of the proposed method, a comparison between the laboratory evaluation results and field data is made. Results show that the laboratory evaluation results under deep-well drilling conditions are consistent with the field data. However, the evaluation under ambient conditions overestimates the inhibition property of the tested fluid and brings a risk of wellbore instability. The developed quantitative method can be a new way to evaluate and optimize the inhibition property of drilling fluid for deep mudstone. [ABSTRACT FROM AUTHOR]

Carbonate rocks in westward oilfield are characterized by deep bury, high temperature, rich in fracture-cave and well collapse, blocking and burying of testing tool always appear in the open-hole completion well formation in the process of production. The reasons of well collapse have analyzed in this article based on in-situ data, at the same time, since the high temperature and high pressure of formation, comprehensive prediction model about borehole stability has been set up, considering with temperature field, flow field, fracture occurrence and hydration. Collapse mechanism of openhole completion deep well in high temperature hydration carbonate stratum also been analyzed. The research results indicated that the minimum bottom hole pressure of maintain wellbore stability acquired from this model is 2-3 MPa higher than that from other conventional models, which promote prediction accuracy; rock strength increases at first and then decreases with the fracture dip from 0° to 90°; The most secure formation is that the formation dip keeps in line with direction of minimum horizontal stress and the fracture dip is lower than 20°, besides, the second is the condition that formation dip consistent with maximum horizontal stress direction and fracture dip is greater than 60°. The minimum of bottom hole pressure maintaining wellbore stability increase with the decrease of inner friction coefficient and cohesive of weak surface after hydration, and increase with stress difference increasing. [ABSTRACT FROM AUTHOR]

Hydraulic fracture propagation is greatly influenced by mode-II fracture toughness since this is one of the factors which determine whether a fracture diverts. Direct measurement of rock fracture toughness is constrained by high cost, limited number of available cores and long turn around time. Therefore, to overcome these constrains, it is necessary to develop an effective mode-II fracture toughness test which can be used in a prediction analysis for deep rock formations. Consequently, a mode-II fracture toughness test system was designed for rocks using the straight-notched Brazilian disc (SNBD) test methodology. In the experiment, this system was used to test 20 rock samples from the WG oilfield. This enabled a fracture toughness prediction model to be established, based on an analysis of the test data. H341 acoustic, density and gamma-ray logging data were used to predict horizontal stresses and rock tensile strength. When combined with the mode-II fracture toughness prediction model, continuous values were predicted, which were successfully confirmed by field fracturing practices. It was confirmed, therefore, that this successful method met the need of providing continuous fracture toughness data during field fracturing operations. [ABSTRACT FROM AUTHOR]

PetroChina's Xinjiang oilfield has a large quantity of tight oil reserves and hydraulic fracturing technology has been widely used to achieve commercial production. Some parts of this tight glutenite formation are laumontite-rich and the actual productivity of the hydraulically fractured wells is less than expected. To figure out the ways that laumontite affects tight glutenite well productivity, comprehensive experimental and numerical simulation studies have been conducted to investigate the rock mechanical properties, fluid flow behaviors and the major controlling factor of productivity. Laboratory results indicate that the tight glutenite formation with higher laumontite content has higher initial porosity, permeability but lower yield strength and more severe stress sensitivity in both permeability and fracture conductivity. For laumontite-rich glutenite rocks, there are commonly three types of rock deformation during the loading process: elastic compression, shear dilation and shear enhanced compaction. Both elastic compression and shear enhanced compaction will cause the reduction on rock porosity and permeability. A fully coupled finite element model (FEM) considering stress-induced permeability evolution was introduced to simulate the production process. Permeability evolution models of three different deformation stages were presented, respectively. Simulation results showed that our model is in good agreements with the well testing data. The simulated oil production characteristics for permeability evolution coupled and uncoupled models were discussed. Results showed the strong stress-induced permeability reduction is the major factor that laumontite causing the low and quickly declining oil rates. Initial permeability has a positive effect on productivity and stress-induced fracture conductivity reduction has slight influence on productivity. The results of this paper indicate that the stress-induced permeability evolution in the oil production process must be considered to accurately evaluating reservoirs in the studied area. [ABSTRACT FROM AUTHOR]

The Efficient development of shale reservoirs becomes increasingly dependent upon infill wells in China to stabilize the gas production. The accurate calculation of dynamic evolution of stress field is important for the design of fracturing and infill wells. The extraction of gas flow results in stress-sensitive and significantly alters the original in-situ stress field, which brings difficulties on geomechanical design for fracturing treatment. Hitherto, the main factors that affect the principal stress alteration is unclear, especially when considering the interference between fractures and wells. Besides, the transport mechanisms of shale gas flow are complex, which bring difficulties in the modeling of deformable multi-continuum. In this paper, an adaptive model that couples multi-continuum matrix and discrete fractures is developed. According to the effective stress coefficients of matrix pores and natural fractures, the total deformation is decomposed into two parts: matrix pore pressure depletion induced deformation and natural fracture pressure depletion induced deformation. The model is then validated to simulate hydromechanical coupling processes in fractured-shale reservoirs during the production period. Sensitivity analysis of stress alteration is also performed to study the alteration angle of the minimum horizontal principal stress during production. The modeling results show that the pressure depletion in natural fractures is the fastest, which dominates the shale deformation. Besides, the gas desorption in organic matters enlarges the alteration angle of the minimum horizontal principal stress during production. Finally, we find the difference between adsorption rate and desorption rate, instead of the total adsorbed gas amount, determines the adsorbed gas production. • A hierarchical approach integrating DFNs with multi-continuum concept to model gas transport in shale. • Impacts of pressure depletion patterns of three continua on the stress field are considered. • The gas flow and the rock deformation are fully coupled. [ABSTRACT FROM AUTHOR]

Formation lithology identification is of great importance for reservoir characterization and petroleum exploration. Previous methods are based on cutting logging and well-logging data and have a significant time lag. In recent years, many machine learning methods have been applied to lithology identification by utilizing well-logging data, which may be affected by drilling fluid. Drilling string vibration data is a high-density ancillary data, and it has the advantages of low-latency, which can be acquired in real-time. Drilling string vibration data is more accessible and available compared to well-logging data in ultra-deep well drilling. Machine learning algorithms enable us to develop new lithology identification models based on these vibration data. In this study, a vibration dataset is used as the signal source, and the original vibration signal is filtered by Butterworth (BHPF). Vibration time–frequency characteristics were extracted into time–frequency images with the application of short-time Fourier transform (STFT). This paper develops lithology classification models using new data sources based on a convolutional neural network (CNN) combined with Mobilenet and ResNet. This model is used for complex formation lithology, including fine gravel sandstone, fine sandstone, and mudstone. This study also carries out related model accuracy verification and model prediction results interpretation. In order to improve the trustworthiness of decision-making results, the gradient-weighted class-activated thermal localization map is applied to interpret the results of the model. The final verification test shows that the single-sample decision time of the model is 10 ms, the test macro precision rate is 90.0%, and the macro recall rate is 89.3%. The lithology identification model based on vibration data is more efficient and accessible than others. In conclusion, the CNN model using drill string vibration supplies a superior method of lithology identification. This study provides low-latency lithology classification methods to ensure safe and fast drilling. [ABSTRACT FROM AUTHOR]

Water uptake induced by fluid–rock interaction plays a significant role in the recovery of flowback water during hydraulic fracturing. However, the existing accounts fail to fully acknowledge the significance of shale anisotropy on water uptake typically under in situ reservoir temperature. Thus we investigated the shale-hydration anisotropy using two sets of shale samples from the Longmaxi Formation in Sichuan Basin, China, which are designated to imbibe water parallel and perpendicular to shale bedding planes. All the samples were immersed in distilled water for one to five days at 80 °C or 120 °C. Furthermore, samples' topographical and elemental variations before and after hydration were quantified using energy-dispersive spectroscopy–field-emission scanning electron microscopy. Our results show that shale anisotropy and imbibition time strongly affect the width of pre-existing micro-fracture in hydrated samples. For imbibition parallel to lamination, the width of pre-existing micro-fracture initially decreases and leads to crack-healing. Subsequently, the crack surfaces slightly collapse and the micro-fracture width is enlarged. In contrast, imbibition perpendicular to lamination does not generate new micro-fracture. Our results imply that during the flowback process of hydraulic fracturing fluid, the shale permeability parallel to bedding planes likely decreases first then increases, thereby promoting the water uptake. [ABSTRACT FROM AUTHOR]