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Due to strong stress sensitivity resulted from unconventional tight formationsit is of practical interest to formulate a reasonable pressure drawdown plan to improve gas extraction recovery. The impact of water-shale interactions on the reservoir permeability was previously ignored in the managed pressure drawdown optimization. The controlled-pressure production dynamic analysis was mostly conducted using numerical simulation, lack of rigorous theoretical support. Hence in this paper, a theoretical production prediction model was proposed and verified with HIS RTA 2015by incorporating multiple pressure drawdown mechanisms and various non-linear gas flow process. The on-site production effects dominated by two different pressure drop methods was further compared, indicating that compared to depressurization production, the production reversion can occur in the controlled pressure production process and the EUR of single well can be increased by about 30% under the control of managed pressure drawdown approach. Finally, the pressure drawdown optimization strategy was carried out on the field test from the both production effect and economic benefits, which demonstrated that the best economic solution can generally be obtained in the early stage of production. The research results can be closely linked to the on-site production practice of shale gas wells, providing insights into designing optimized production strategy scheme. [ABSTRACT FROM AUTHOR]

Archie's parameters are substantial to be investigated in the evaluation of water saturation. Many researchers adhered to the opinion that Archie's equation can still be applied to water saturation calculation in shale if the accuracy of relative parameters could be improved. External conditions, such as temperature, confining pressure, water salinity, wettability, and displacement, may influence the determination of Archie's parameters. The aim of the study is to investigate the effect of salinity on Archie's parameters and their correlation with mineral composition and pore structure. The mineral contents and petrophysical properties were firstly acquired through X-ray diffraction (XRD) and basic measurements. Rock-electric experiments under different salinity were conducted on deep shale samples taken from Longmaxi (LMX) Formation in Luzhou (LZ). The results indicate that Archie's parameters of " a ," " b ," " m ," and " n " under actual brine salinity are assigned to 1.47, 1, 1.26, and 1.6, respectively. Our cementation factor is lower than that in other studies including (shaly) sandstones, carbonates, and shales, probably due to the extremely low porosity in study area. Salinity has a positive effect on cementation factor (m) and saturation exponent (n), suggesting the traditional assignment to Archie's parameters is inappropriate. It was concluded that the complicated pore structure and high porosity mainly associated with clay mineral may trigger the increased cementation factor. Further mathematical derivations confirmed that the rock resistivity is inextricable from pore system and establish a physical model. The paper provides a solid evidence base for further understanding and evaluation of water saturation in unconventional shale reservoirs, more significantly, innovatively unveils the research into Archie formula in deep shale reservoirs of southern Sichuan basin. [ABSTRACT FROM AUTHOR]

The shale gas productivity model based on shale gas nonlinear seepage mechanism is an effective way to reasonably predict productivity. The incomplete gas nonlinear effects considered in the current production prediction models can lead to inaccurate production prediction. Based on the conventional five-zone compound flow model, comprehensive gas nonlinearities were considered in the improved compound linear flow model proposed in the paper and a semianalytical solution for productivity was obtained. The reliability of the productivity model was verified by the field data, and then, the 20-year production performance analysis of the gas well was studied. Ultimately, the key influencing factors of the fracture control stage and matrix control stage have been analyzed. Research indicated the following: (1) the EUR predicted by the productivity model is higher than the EUR that the comprehensive nonlinear effects are not considered, which demonstrated that the various nonlinear effects cannot be neglected during the production prediction to ensure the greater calculation accuracy; (2) during the early production stage of shale reservoir, the adsorbed gas is basically not recovered, and the cumulative adsorption contribution rate does not exceed 10%. The final adsorption gas contribution rate is 23.28%, and the annual adsorption rate can exceed 50% in the 20th year, showing that free gas and adsorbed gas are, respectively, important sources of the early stage of production and long-term stable production; (3) the widely ranged three-dimensional fracturing reformation of shale reservoirs and reasonable bottom hole pressure in the later matrix development process should be implemented to increase the effective early production of the reservoir and ensure the earlier gas production process of the matrix development. The findings of this study can help for better ensuring the prediction accuracy of the estimated ultimate recovery and understanding the main influencing factors of the dynamic performance of gas wells so as to provide a theoretical reference for production optimization and development plan formulation of the shale gas reservoirs. [ABSTRACT FROM AUTHOR]

The shale gas productivity model based on shale gas nonlinear seepage mechanism is an effective way to reasonably predict productivity. The incomplete gas nonlinear effects considered in the current production prediction models can lead to inaccurate production prediction. Based on the conventional five-zone compound flow model, comprehensive gas nonlinearities were considered in the improved compound linear flow model proposed in the paper and a semianalytical solution for productivity was obtained. The reliability of the productivity model was verified by the field data, and then, the 20-year production performance analysis of the gas well was studied. Ultimately, the key influencing factors of the fracture control stage and matrix control stage have been analyzed. Research indicated the following: (1) the EUR predicted by the productivity model is higher than the EUR that the comprehensive nonlinear effects are not considered, which demonstrated that the various nonlinear effects cannot be neglected during the production prediction to ensure the greater calculation accuracy; (2) during the early production stage of shale reservoir, the adsorbed gas is basically not recovered, and the cumulative adsorption contribution rate does not exceed 10%. The final adsorption gas contribution rate is 23.28%, and the annual adsorption rate can exceed 50% in the 20th year, showing that free gas and adsorbed gas are, respectively, important sources of the early stage of production and long-term stable production; (3) the widely ranged three-dimensional fracturing reformation of shale reservoirs and reasonable bottom hole pressure in the later matrix development process should be implemented to increase the effective early production of the reservoir and ensure the earlier gas production process of the matrix development. The findings of this study can help for better ensuring the prediction accuracy of the estimated ultimate recovery and understanding the main influencing factors of the dynamic performance of gas wells so as to provide a theoretical reference for production optimization and development plan formulation of the shale gas reservoirs. [ABSTRACT FROM AUTHOR]

[Display omitted] • Revealing the effect of CO 2 on oil potential energy in nanopores. • CO 2 solubility and oil swelling factor explained within nanopores. • Influence of CO 2 on the recovery law of different components in oil. • Analysis of different water film thickness on CO 2 enhanced oil recovery. Understanding the mechanisms of CO 2 extraction or flooding are vital for enhancing oil recovery (EOR) in tight reservoirs. In this study, the CO 2 EOR mechanism in the displacement-affected area (DPAA) and diffusion-affected area (DFAA) of quartz nanopores were thoroughly investigated using molecular dynamics simulation techniques. First, the following two contents were mainly simulated, namely CO 2 flooding oil in the single/double nanopores of DPAA and CO 2 extraction oil in dead-end nanopores of the DFAA with and without the water film. Then, tight oil potential energy, threshold capillary pressure, CO 2 solubility, and oil swelling in nanopores were calculated to clarify the effects of CO 2 on oil transport. Moreover, different CO 2 injection/flowback rates and different water film thicknesses on dead-end nanopores on oil recovery were discussed. In the DPAA, the CO 2 solubility and the oil swelling factor gradually decreased with distance from the CO 2 -oil interface (Y = 0 nm), where the higher the injection rate, the more easily the CO 2 dissolved in the oil. However, the injection rate of CO 2 was inversely proportional to oil recovery. In addition, it took longer for the displacement efficiency in the 6 nm pore of double pores to reach the same displacement efficiency as in the single 6 nm pore. In the DFAA, the effect of flowback rate on the displacement efficiency of oil was relatively low. However, the thickness of the water film was a key factor that affected the oil displacement efficiency in the DFAA. [ABSTRACT FROM AUTHOR]

Predicting the production behaviors of shale gas wells is of great importance for further developing future unconventional hydrocarbon strategies. An accurate prediction production, as well as reliable shale gas production models, are required to fully understand the shale gas exploitation budget. However, a major problem with classical analytic methods is the insufficient accuracy of the existing models, the time-consuming collection of historical production data, and the costly computational expense. To minimize this problem, a combination of the exponential smoothing method, autoregressive integrated moving average (ARIMA) model, and long short-term memory (LSTM) model was proposed to provide robust support for the production behaviors of shale gas. In this paper, we employed shale gas well production data to establish a database for model training and optimized the predicted model. Hereby, we sought to evaluate the production data predicted by conventional analytical methods, the exponential smoothing method, the ARIMA model, and the LSTM model. Shortly afterward, we objectively compared the predicted results obtained by the novel LSTM model and traditional analytical methods, such as Arps, stretched exponential decline (SEPD), and the Duong model. Herein, we compared the computational cost between the LSTM model and traditional numerical simulation. The combined interpretation of the proposed model demonstrates that the LSTM model achieved scientific accuracy and outstanding results in both short-term and long-term predictions, and realized production prediction of the adjacent well, with excellent agreement with the real shale gas production and a low error, making it an effective tool in forecasting shale gas production. This assay could be used as a potential approach for evaluating deep learning in the petroleum industry and for predicting the future production of unconventional hydrocarbons. [Display omitted] • A framework for shale gas production potential estimation was developed. • A deep-learning-based time series analysis model was built to predict the short-term and longterm shale gas production, based on thousands of in-situ production data samples from three shale gas wells. • Computational cost of the shale gas production prediction was significantly reduced with proposed long short-term memory model. • Objectively compare the advantage and drawback forecasting production among conventional analytical methods, exponential smoothing algorithm, ARIMA, and LSTM model. • The study shed lights on the few-shot learning applications in shale gas production prediction. [ABSTRACT FROM AUTHOR]

Many factors need to be considered in the evaluation of tight conglomerate reservoirs, including the microscopic pore-throat structure, pore connectivity, lithology, porosity, permeability, and clay mineral content. The contents and types of clay minerals reflect the mineral evolution process during the deposition of the reservoir and can reflect the reservoir's physical properties to a certain extent. In this study, cores from the Baikouquan Formation in Mahu were used to comprehensively analyze the effects of the clay mineral content on the physical properties of a tight conglomerate reservoir, including field emission scanning electron microscopy (FE-SEM), casting thin section observations, X-ray diffraction (XRD), interface property testing, high-pressure mercury injection, low temperature N2 adsorption, and nuclear magnetic resonance (NMR)-movable fluid saturation testing. The results revealed that differences in different lithologies lead to differences in clay mineral content and pore structure, which in turn lead to differences in porosity and permeability. The interface electrification, adsorption, and specific surface area of the reservoir are positively correlated with the clay mineral content, which is mainly affected by the smectite content. As the clay mineral content increases, the proportion of nanoscale pore throats increases, and the core becomes denser. The saturation of the movable fluid controlled by the >50 nm pore throats in the tight conglomerate ranges from 8.7% to 33.72%, with an average of 20.24%. The clay mineral content, especially the I/S (mixed layer of Illite and montmorillonite) content, is negatively correlated with the movable fluid. In general, the research results clarified the relationship between the lithology and physical properties of clay minerals and the microscopic pore structure of the tight conglomerate reservoirs in the Baikouquan Formation in the Mahu area. [ABSTRACT FROM AUTHOR]

The shale gas productivity model based on shale gas nonlinear seepage mechanism is an effective way to reasonably predict productivity. The incomplete gas nonlinear effects considered in the current production prediction models can lead to inaccurate production prediction. Based on the conventional five-zone compound flow model, comprehensive gas nonlinearities were considered in the improved compound linear flow model proposed in the paper and a semianalytical solution for productivity was obtained. The reliability of the productivity model was verified by the field data, and then, the 20-year production performance analysis of the gas well was studied. Ultimately, the key influencing factors of the fracture control stage and matrix control stage have been analyzed. Research indicated the following: (1) the EUR predicted by the productivity model is higher than the EUR that the comprehensive nonlinear effects are not considered, which demonstrated that the various nonlinear effects cannot be neglected during the production prediction to ensure the greater calculation accuracy; (2) during the early production stage of shale reservoir, the adsorbed gas is basically not recovered, and the cumulative adsorption contribution rate does not exceed 10%. The final adsorption gas contribution rate is 23.28%, and the annual adsorption rate can exceed 50% in the 20th year, showing that free gas and adsorbed gas are, respectively, important sources of the early stage of production and long-term stable production; (3) the widely ranged three-dimensional fracturing reformation of shale reservoirs and reasonable bottom hole pressure in the later matrix development process should be implemented to increase the effective early production of the reservoir and ensure the earlier gas production process of the matrix development. The findings of this study can help for better ensuring the prediction accuracy of the estimated ultimate recovery and understanding the main influencing factors of the dynamic performance of gas wells so as to provide a theoretical reference for production optimization and development plan formulation of the shale gas reservoirs. [ABSTRACT FROM AUTHOR]

[Display omitted] • The CO 2 recovery from different types of quartz nanopores was discussed. • The higher the amount of CO 2 dissolved could improve the flow velocity of oil and gas in nanopores. • There were three flow modes in the oil–water two-phase flow process: WDOWF, WFOWF and ODOWF. • The effect of CO 2 on the distribution and flow of oil–water depends on the flow modes of oil–water. Multiphase flow in nanoporous media is ubiquitous in various fields, including geophysics, physical chemistry, and bioengineering. Tight sandstone reservoirs have relatively well-developed nanoscale pores. Understanding the mechanism of multiphase flow in nanoporous media is crucial for enhanced oil recovery. In this study, the pore distribution characteristics of tight sandstone cores were visually observed and analyzed through Wood's metal injection experiments and scanning electron microscopy. Subsequently, molecular dynamics simulations were used to establish a multiple-pore model with/without bound water. The mainstream channel (MC) was selected as the research pore, and multiple groups of molecular dynamics models with different oil–gas–water ratios were established to simulate multiphase flow. The results showed that the micro-nano-scale pore throats of the tight sandstone were well developed, necessitating a study of fluid flow characteristics within the nanopores. In the process of CO 2 injection production, the bound water could occupy dead-end pores (DEP) and small channels (SC), which was beneficial to the oil recovery. When there was no bound water, the MC mainly relied on the CO 2 displacement for oil recovery, while the DEP of the MC, the DEP of the SC, and the SC mainly relied on oil expansion and CO 2 extraction. In the MC nano-confined fluid flow process, the larger the proportion of CO 2 was, the lower the viscosity of the oil was, and the more easily it could flow. However, when water was present, three flow modes formed: water drop oil–water flow (WDOWF), water film oil–water flow (WFOWF), and oil drop oil–water flow (ODOWF), among which ODOWF had the greatest influence on the flow of bound fluid in the nanopores. The injection of CO 2 could improve the flow in the WDOWF and WFOWF modes and had no positive effect on the ODOWF. [ABSTRACT FROM AUTHOR]

• The mass transfer experiment of CO 2 -oil system was studied. • The oil phase swelling effect was characterized through the modified PR-EOS equation. • Diffusion coefficient of CO 2 and swelling factor of oil was calculated by using a variety of methods. • Effects of CO 2 on the potential energy and self-diffusion coefficient of oil. The oil volume expansion and CO 2 diffusion are one of the main mechanism of CO 2 -enhanced oil recovery (CO 2 -EOR). This paper established a series of experiments, numerical simulations, and molecular dynamics (MD) simulations to describe mass transfer behaviors between oil–gas phases. Expressly, the CO 2 diffusion coefficient and light oil swelling factor are signification parameters to quantify and analyze these behaviors. In detail, the CO 2 diffusion coefficient and the oil swelling factor were obtained from the traditional pressure decay method and the advanced MD simulation. Synthetically, the pressure decay method and MD simulation results were mutually verified. The results showed that the equilibrium pressure was proportional to the mole fraction of CO 2 and inversely proportional to the mole fraction of light oil. The equilibrium time was proportional to the mole fraction of CO 2 and light oil. At the temperature of 333.15 K and the initial pressure of 7.5 MPa, the CO 2 diffusion coefficient in light oil was positively correlated with the relative molar proportion of CO 2 , while the light oil swelling factor was vice versa. In addition, the closer to the CO 2 -light oil interface, the greater the light oil's potential energy and self-diffusion coefficient, and the stronger the transport ability. [ABSTRACT FROM AUTHOR]

CO 2 -enhanced oil recovery (CO 2 -EOR) technology has shown great application potential in the development of tight reservoirs. Since the proportion of nano-pores in tight oil reservoirs exceeds 77%, it is necessary to further study the occurrence state of crude oil in nano-pores. In this paper, the molecular dynamics simulation was applied to study the adsorption and diffusion behaviors of multi-component crude oil in quartz (hydrophilic) nano-pores. Besides, the density discretization method was used to investigate the occurrence characteristics of crude oil, the proportion of movable fluid in nano-pores, and the effects of CO 2 and polar molecules (C 3 H 6 O) on the adsorption characteristics of crude oil. The simulation results showed that the adsorption state of crude oil in the quartz nano-pores was in the form of 4 adsorption layers with a thickness of 0.45 nm each. In nano-pores, the oil molecules with longer molecular chains were more likely to aggregate and adsorb on the quartz surface. Among them, polar oil molecules have the strongest adsorption capacity on the quartz surface. Moreover, the crude oil potential energy and the self-diffusion coefficient gradually increased from the vicinity of the quartz wall and tended to be stable in the free layer. Meanwhile, the content of movable crude oil gradually augmented with the increasement of nanometer pore width and temperature. Furthermore, the pressure had little effect on the density distribution of crude oil in the pores. In contrast, the temperature had a more significant effect on the density distribution of the adsorption layer. At last, due to the more substantial adsorption capacity of CO 2 on the rock surface, the crude oil adsorbed initially on the rock surface would be stripped off by CO 2 , converting from irreducible oil to moveable oil. [Display omitted] • Distribution profile of adsorbed and free crude oil in various nanoslits. • The self-diffusion coefficient and potential energy of crude oil at different positions. • Temperature has a great influence on the occurrence state of crude oil. • Effects of different proportions of CO 2 on the occurrence state of crude oil in nanoslits. [ABSTRACT FROM AUTHOR]

CO 2 huff and puff (HNP) is one of the most effective methods to improve tight oil recovery after the primary depletion process. The seepage mechanisms between CO 2 and crude oil are complicated in porous media during CO 2 HNP process. Therefore, in this paper, the CO 2 HNP process of Chang-7 tight oil reservoir, Ordos Basin, China, was studied by nuclear magnetic resonance (NMR) technology, microscopic observation and numerical simulation. Experimentally, using NMR technology and microscopy methods, the distribution characteristics of residual oil during CO 2 HNP process were measured intuitively. Numerically, a group of core-scale and field-scale simulations considering molecular diffusion and asphaltene precipitation were established to further verify and elongate the experimental results. The results show that at the initial state, the crude oil in the tight core was mainly distributed in nanopores, sub-micro-nanopores and sub-micropores, where the oil content exceeded at least 73% in these pores. During CO 2 HNP process, the oil recovery was more pronounced for the 1st and 2nd rounds than for 3rd to 5th rounds. Notably, even if the cores with more nano-pores were more favorable for the 4–5th CO 2 HNP rounds, the oil molecules in nanopores were still difficult to be available. Moreover, the CO 2 sweep scope could be divided into displacement affected region and diffusion affected region. CO 2 could effectively drive the crude oil in the displacement affected region. While the oil could be successfully displaced by dissolved gas flooding in the diffusion affected region only under the appropriate conditions. Meanwhile, the core-scale numerical models confirmed that it was necessary to consider molecular diffusion and asphaltene precipitation factors, which would make the simulation results in line with the experiment. In terms of the ultimate oil recovery, the field-scale model only considering the diffusion (2.456%) > the model both considering the diffusion and asphaltene (2.436%) > the model without considering the diffusion and asphaltene deposition (2.412%) > the model only considering the asphaltene deposition (2.388%). • The oil were difficult to be available in nanopores due to the nano-constraint effect. • The CO2 displacement area was associated with diffusion and asphaltene precipitation. • SP-T2 spectrum and microscopic image were applied to obtain CO2 sweep scope. • A group of simulations were established to analyse the effect of CO2 sweep scope. [ABSTRACT FROM AUTHOR]