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To facilitate the recovery of natural gas hydrate (NGH) deposits in the South China Sea, we have designed and developed the world's largest publicly reported experimental simulator for NGH recovery. This system can also be used to perform CO₂ capture and sequestration experiments and to simulate NGH recovery using CH₄/CO₂ replacement. This system was used to prepare a shallow gas and hydrate reservoir, to simulate NGH recovery via depressurization with a horizontal well. A set of experimental procedures and data analysis methods were prepared for this system. By analyzing the measurements taken by each probe, we determined the temperature, pressure, and acoustic parameter trends that accompany NGH recovery. The results demonstrate that the temperature fields, pressure fields, acoustic characteristics, and electrical impedances of an NGH recovery experiment can be precisely monitored in real time using the aforementioned experimental system. Furthermore, fluid production rates can be calculated at a high level of precision. It was concluded that (1) the optimal production pressure differential ranges from 0.8 to 1.0 MPa, and the wellbore will clog if the pressure differential reaches 1.2 MPa; and (2) during NGH decomposition, strong heterogeneities will arise in the surrounding temperature and pressure fields, which will affect the shallow gas stratum.

Production prediction is crucial for the recovery of hydrocarbon resources. However, accurate and rapid production forecasting remains challenging for unconventional reservoirs due to the complexity of the percolation process and the scarcity of available data. To address this problem, a novel model combining a long short-term memory network (LSTM) and support vector regression (SVR) was proposed to forecast tight oil production. Three variables, the tubing head pressure, nozzle size, and water rate were utilized as the inputs of the presented machine-learning workflow to account for the influence of operational parameters. The time-series response of tight oil production was the output and was predicted by the optimized LSTM model. An SVR-based residual correction model was constructed and embedded with LSTM to increase the prediction accuracy. Case studies were carried out to verify the feasibility of the proposed method using data from two wells in the Ma-18 block of the Xinjiang oilfield. Decline curve analysis (DCA) methods, LSTM and artificial neural network (ANN) models were also applied in this study and compared with the LSTM-SVR model to prove its superiority. It was demonstrated that introducing residual correction with the newly proposed LSTM-SVR model can effectively improve prediction performance. The LSTM-SVR model of Well A produced the lowest prediction root mean square error (RMSE) of 5.42, while the RMSE of Arps, PLE Duong, ANN, and LSTM were 5.84, 6.65, 5.85, 8.16, and 7.70, respectively. The RMSE of Well B of LSTM-SVR model is 0.94, while the RMSE of ANN, and LSTM were 1.48, and 2.32.

The multi-scaled pore networks of shale or tight reservoirs are considerably different from the conventional sandstone reservoirs. After hydraulic fracturing treatment, the spontaneous imbibition process plays an important role in the productivity of the horizontal wells. Applying the color-gradient model of Lattice Boltzmann Method (LBM) accelerated with parallel computing, we studied the countercurrent spontaneous imbibition process in two kinds of pore structures with different interlacing distributions of large and small pores. The effect of geometry configuration of pore arrays with different pore-scale and the capillary number $Ca$ on the mechanism of counter-current spontaneous imbibition as well as the corresponding oil recovery factor are studied. We found that the wetting phase tends to invade the small pore array under small $Ca$ in both types of geometry configurations of different pore arrays of four pore arrays zones. The wetting phase also tends to invade the pore array near the inlet for injecting the wetting phase no matter if it is a large pore array or small pore array except for the situation when the $Ca$ is large to a certain value. In this situation, the small pore arrays show resistance to the wetting phase, so the wetting phase doesn't invade the small pore near the inlet, but invades the large pore preferentially. Both the geometry configurations of different pore arrays and $Ca$ have a significant effect on the oil recovery factor. This work will help to solve the doubt about the selectivity of the multi-scaled pores of the wetting phase and the role of pores with different sizes in imbibition and oil draining in countercurrent spontaneous imbibition processes.

Shale hydration and swelling is the main obstacle to the development of shale gas utilizing water-based drilling fluids (WBDFs). In this work, the inhibition mechanism of alkylammonium inhibitor and alkylamine inhibitor adsorbed on sodium bentonite (Na+Bent) are investigated using infrared spectroscopy (FT-IR), scanning electron microscopy (SEM), X-ray diffraction (XRD), zeta potential, particle size distribution tests, and thermogravimetry analysis (TGA). The results suggest that HTB and HMD can be inserted into the interlamination of Na+Bent and minimize the basal spacing compared to hydrated Na+Bent. HTB and HMD are inserted between the Na+Bent layers in a single-layer tiled manner and replace the sodium ions that are firmly fixed between the layers. Eventually, water molecules are removed from the interlayer Na+Bent. The interaction between the quaternary ammonium group and Na+Bent is more significant than between the primary amine group and Na+Bent. The inhibition performance suggests that HTB inhibits Na+Bent hydration and swelling more substantially than other inhibitors, indicating that the inhibition performance of the two quaternary ammonium groups is greater than that of the two primary amine groups. Therefore, HTB can be used as intercalation inhibition in WBDFs and has tremendous application value.

Through the stimulation method of large-scale hydraulic fracturing, the spontaneous imbibition capacity of the water phase in the shale reservoir has great influence on the effect of stimulation. Generally, the lacustrine shale has the characteristics of high clay minerals content, strong expansibility, development of nanopores and micro-pores, and underdevelopment of fractures, which leads to the unclear behavior of spontaneous imbibition of aqueous phase. The lacustrine shale of Da'anzhai Member and marine shale of Longmaxi Formation in Sichuan Basin were selected to prepare both the shale matrix sample and fractured shale sample, and the spontaneous imbibition experiment of simulated formation water was carried out. By means of an XRD test, SEM observation, nuclear magnetic resonance test and linear expansion rate test, the mineral composition, the structure of pores and fractures, the capacity of hydration and expansion of both lacustrine and marine shale are compared and analyzed. The results show that the average spontaneous imbibition rate of lacustrine shale is 60.8% higher than that of marine shale within the initial 12 hours of imbibition. The lacustrine shale has faster imbibition rate than the marine shale in the initial stage of spontaneous imbibition. However, the lacustrine shale has underdeveloped pores and fractures, as well as poor connectivity of pores. Besides, the strong hydration and expansion of clay minerals can easily lead to dispersion and migration of clay minerals on the fracture surface, which will plug up the seepage channels, resulting in poor capacity of spontaneous imbibition. The spontaneous imbibition rate in the middle and late stage of Lacustrine shale is obviously lower than that of the marine shale. The overall spontaneous imbibition rate ability of the lacustrine shale is less than that of the marine shale. According to the characteristics of water imbibition of lacustrine shale, considering the dual effects of hydration expansion of clay minerals on the effective reconstructed volume, the microfractures can be initiated and extended by fully utilizing the hydration of shale. Acidification treatment, oxidation treatment or high temperature treatment can be used to expand pore space, enhance water phase imbibition capacity and improve multi-scale mass transfer capacity of the lacustrine shale.

The paper is devoted to the two-phase flow simulation. The gas-condensate mixture flow in a horizontal pipe under high pressure is considered. The influence of the equation of state (EOS) choice for mixture properties modelling on the flow regime calculation results is studied for gas with high content of methane homologues. An analytical overview of the methods to predict the flow pattern is provided. Based on this analysis, two techniques are selected. For these techniques, values of density and viscosity for each phase are required. Density calculation for the gas phase is performed with Van der Waals based EOS. The propriate EOS is selected based on studies of calculation errors for test mixtures. Calculation of liquid phase density is done by means of Patela-Teja and Guo-Du equations, two different models are considered for viscosity estimation. The flow patterns of gas-condensate mixture in a range of temperatures and pressures are calculated and verified via probability map. The results of study allow to recommend the Brusilovsky EOS for calculation of densities for similar gas mixtures and make more rigorous flow regime evaluation. The probability map shows that for the chosen composition and parameters of media the flow pattern is mostly transitional between segregated and annular independent from EOS.

To remediate the problem of severe or total losses, and meet the requirements of borehole plugging and pumping at different well depths, a novel crosslinked polymer gel (named HPG/Zr gel) with controlled gelation time and high gel strength was developed as loss circulation material, which mainly comprised hydroxypropyl guar gum, zirconium compound and triethanolamine. The influence of hydroxypropyl guar gum concentration, zirconium compound concentration, triethanolamine concentration and temperature on the gelation time of HPG/Zr gel was evaluated. In addition, the performance of HPG/Zr gel was investigated in terms of temperature resistance and shear resistance property, plugging ability and supporting cement slurry ability. According to the results, HPG/Zr gel can form a viscoelastic body with a network structure, and its gelation time can be practically adjustable. The results of the plugging experiment at different temperatures, pressures and pore sizes of quartz sand revealed that HPG/Zr gel could effectively plug sand pores at 150°C, and its pressure-bearing capacity can be up to 5 MPa. Employing its flow resistance and ability of supporting cement slurry, HPG/Zr gel was successfully applied in two geological boreholes by combining with cement slurry. Overall, the results of laboratory research and field tests indicate that HPG/Zr gel is useful for mitigating the lost circulation, and it is of huge importance to engineering applications.

The geomechanical behavior of salt rocks is a significant concern during drilling and development operations in some hydrocarbon reservoirs and underground gas storage sites. In this study, the static and dynamic salt rock geomechanical properties from a field in southwest Iran were evaluated using experiments such as waves' velocities, and thermo-mechanical coupled uniaxial and triaxial compression tests. As a result and by considering both the petrophysical well logs and laboratory data of the waves’ velocities, it is observed that the elastic properties of the core samples are concentrated within a narrow range unless an abnormality causes scatter. The results of uniaxial compression tests showed that rock strength decreases with increasing temperature linearly. In addition, the reduction of rock strength was observed with increasing porosity of the core samples as expected. In the case of triaxial compression tests, applying confining pressure on the core sample caused an increment in rock strength, while temperature decreased rock strength. The temperature also increased cohesion and decreases friction angle. The ratio of changes in stress to strain was used to investigate the dynamic changes in the geomechanical state. The maximum 0.25 damage factor was observed for the core samples for different definitions of the damage factor. Finally, we propose a novel analytical model to predict the stress-strain behavior of salt rocks at different conditions. The model was validated using experimental results and indicated a satisfactory accuracy.

The brittleness index plays a significant role in the hydraulic fracturing design and wellbore stability analysis of shale reservoirs. Various brittleness indices have been proposed to characterize the brittleness of shale rocks, but almost all of them ignored the anisotropy of the brittleness index. Therefore, uniaxial compression testing integrated with geophysical logging was used to provide insights into the anisotropy of the brittleness index for Longmaxi shale, the presented method was utilized to assess brittleness index of Longmaxi shale formation for the interval of 3155–3175 m in CW-1 well. The results indicated that the brittleness index of Longmaxi shale showed a distinct anisotropy, and it achieved the minimum value at β = 45°-60°. As the bedding angle increased, the observed brittleness index (BI_{2_β}) decreased firstly and increased then, it achieved the lowest value at β = 40°–60°, and it is consistent with the uniaxial compression testing results. Compared to the isotropic brittleness index (β = 0°), the deviation of the anisotropic brittleness index ranged from 10% to 66.7%, in other words, the anisotropy of brittleness index cannot be ignored for Longmaxi shale. Organic matter content is one of the main intrinsic causes of shale anisotropy, and the anisotropy degree of the brittleness index generally increases with the increase in organic matter content. The present work is valuable for the assessment of anisotropic brittleness for hydraulic fracturing design and wellbore stability analysis.

Industrial process plants use emergency shutdown valves (ESDVs) as safety barriers to protect against hazardous events, bringing the plant to a safe state when potential danger is detected. These ESDVs are used extensively in offshore oil and gas processing plants and have been mandated in the design of such systems from national and international standards and legislation. This paper has used actual ESDV operating data from four mid/late life oil and gas production platforms in the North Sea to research operational relationships that are of interest to those responsible for the technical management and operation of ESDVs. The first of the two relationships is between the closure time (CT) of the ESDV and the time it remains in the open position, prior to the close command. It has been hypothesised that the CT of the ESDV is affected by the length of time that it has been open prior to being closed (Time since the last stroke). In addition to the general analysis of the data series, two sub-categories were created to further investigate this possible relationship for CT and these are “above mean” and “below mean”. The correlations (Pearson's based) resulting from this analysis are in the “weak” and “very weak” categories. The second relationship investigated was the effect of very frequent closures to assess if this improves the CT. ESDV operational records for six subjects were analysed to find closures that occurred within a 24 h period of each other. However, no discriminating trend was apparent where CT was impacted positively or negatively by the frequent closure group. It was concluded that the variance of ESDV closure time cannot be influenced by the technical management of the ESDV in terms of scheduling the operation of the ESDV.