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The total organic carbon (TOC) is a key geologic parameter for unconventional reservoirs. Conventional empirical [Formula: see text] methods cannot handle the nonlinear relationships between the characteristics of TOC and its well-log responses. Increased data availability has the potential to speed up deep learning applications, which can reasonably propagate the integrated information from well logs to indirectly observable geologic properties, such as TOC. Although the existing convolutional neural network (CNN) has found superior performance to [Formula: see text] for predicting TOC, CNNs feature-learning capability is still constrained by the fact that it can only extract log-specific sequential features of the input logs. However, the cross-log topological association features are potentially essential for the nonlinear mapping between well logs and TOC. Thus, we introduce a novel deep spatial-sequential graph convolutional network (SSGCN) for predicting the TOC by jointly leveraging the cross-log topological association features and log-specific sequential features. Through further use of the previously unaccounted topological interactions, our SSGCN dramatically outperforms the sequence-based CNN. In the southeast Sichuan Basin, SSGCN exhibits beneficial mapping not demonstrated previously: its models achieve a better cross-validation performance within the same gas field wells and a greater generalizability in another gas field well. Our SSGCN method can predict TOC of shale gas field well with the best [Formula: see text] being 0.87 within 1 s on the CPU of a desktop computer, which increases the efficiency of obtaining the TOC parameter. From this study, we recommend graph and sequential convolutions for designing deep learning architectures in the well-log analysis.

The existence of water phase occupies oil flow area and impacts the confined oil flow behavior at the solid substrate in inorganic nanopores of shale oil reservoirs, resulting in a completely different flow pattern when compared with the single oil phase flow. This study proposes an analytical model to describe the water-oil two-phase flow. In this model, water slippage at the solid substrate is considered while oil slip is introduced to calculate the oil movement at the solid-oil boundary in dry conditions. It is proven that the oil flow profiles of both the two-phase model and single-phase model show parabolic shapes, but the oil flow capacity drops when water takes up the flow space and the impact of water is more significant when the pore dimension is smaller than 30 nm. Also, the oil flow velocity at a pore center is found to drop linearly given a larger water saturation in wet conditions. The effects of surface wettability and oil properties on water-oil flow are also discussed. Compared with the existing single-phase models, this model describes oil flow pattern in the wet condition with the incorporation of the influence of nanopore properties, which better predicts the oil transport in actual reservoir conditions. Water-oil relative permeability curves are also obtained to improve oil yield.

ABSTRACT: In this work, we compare experimental data with different kinds of dynamic contact angle (DCA) models firstly, rationality of the values of fitting parameters are then analyzed. Based on the combined model, we modify the classic L-W equation further to consider the influence of DCA in the process of water imbibition in micro and nanoscale hydrophilic capillaries. Besides, the effects of static wettability and pore dimension are investigated. Results show that: 1) The velocity dependences of DCA predicted by different kinds of DCA models are similar to each other and they can all fit well with the experimental data due to the existence of fitting parameters. 2) DCA deviates from equilibrium contact angle (ECA) more in capillaries with larger dimensions, which is due to the lower flow resistance and higher imbibition velocity. 3)With the decreases of the ECA, the deviation between DCA and ECA increases, this is because energy dissipation in the meniscus is higher in more hydrophilic capillaries due to the stronger fluid-wall interaction. 4) For spontaneous water imbibition in hydrophilic capillaries, the influence of DCA is more obvious in capillaries with larger sizes or smaller ECA, where it should be considered for more accurate recovery prediction. 1. INTRODUCTION Capillary imbibition is an interesting and ubiquitous phenomenon in nature, and plays a significant role in many industries (Feng et al. 2018b), such as ultrafine filtration process, irrigation engineering, energy conversion/storage, powder engineering, etc. (Zhang and Pei 2020, Feng et al. 2018b). Specially, in petroleum engineering, imbibition in porous media has important applications in the flowback of fracturing liquid and the huff-puff development of oil and gas field (Tian et al. 2021a). During the imbibition process, fracturing fluid, which is made up of as much as 97 percent water, imbibes into the matrix from the fracture, expelling oil and gas there and is favorable to the final recovery when the pore surface is water-wet (Tian et al. 2021b). Therefore, the imbibition process has great prospects in the development of fractured and unconventional oil and gas reservoirs and the recovery enhancement (Yha et al. 2020).

The minimum miscible pressure (Pm) of CO2-hydrocarbon mixtures in nanopores is a key parameter for CO2-enhanced shale oil recovery. Although the miscible behaviors of CO2-hydrocarbon mixtures in nanopores have been widely investigated through the simulations and calculations, the heterogeneity of shale components with different affinity to hydrocarbons results in the deviation of traditional predictions and motivates us to investigate how the surface properties influence the CO2-hydrocarbon miscible behaviors in nanopores. In this work, we established a model and framework to determine the wettability-dependent physical phenomena and its impact on the Pm of CO2-hydrocarbon in shale nanopores. First, a generalized scaling rule is established to clarify the potential correlation between critical properties shift and wettability based on the analysis of microscopic interactions (fluid-surface interactions and fluid-fluid interactions). Second, a wettability-dependent SKR EOS is structured and a generalized and practical framework for confined phase behavior with different surface wettability is constructed. Subsequently, the Pm of CO2-hydrocarbon mixtures in confined space with various wettability is evaluated with our model. The calculated results demonstrate that the nanoconfined effects on Pm not only relate to the pore dimension but also depend on the contact angle. In an intermediate-wet nanopore, the minimum miscible pressure approaches the bulk value. In an oil-wet nanopore with a width smaller than 100nm, the minimum miscible pressure is suppressed by the confined effects, and the reduction is further strengthened with a reduction in pore dimension and increase of wall-hydrocarbon affinity. Our work uses a macroscopically measurable parameter (contact angle) to characterize the shift of critical properties derived from the microscopic interactions, and further construct a generalized and practical framework for phase behavior and minimum miscible pressure determination in nanopores with different surface properties. The method and framework can make a significant contribution in the area of upscaling a molecular or nanoscale understanding to a reservoir scale simulation in shale gas/oil research.

Summary Imbibition is one of the most common physical phenomena in nature, and it plays an important role in enhanced oil recovery, hydrology, and environmental engineering. The imbibition in a capillary is one of the fluid transports in porous media, and the effect of a dynamic contact angle that changes with the imbibition rate on liquid-liquid imbibition is not clear. In this paper, the molecular kinetic theory (MKT) is used to study the effect of a dynamic contact angle on spontaneous capillary-liquid-liquid imbibition at a micrometer scale. The results show that: Using a scaling time, the effects of various forces in different imbibition systems can be compared, the influence of a dynamic contact angle on imbibition can be characterized by a frictional effect of the three-phase contact line, and the proposed model considering the effect of a dynamic contact angle is better than the model neglecting the effect of a dynamic contact angle. As the displacing phase viscosity increases, the influence of a dynamic contact angle on imbibition strengthens, which is attributed to a decrease in the viscous effect and an increase in the frictional effect during the imbibition process; as the displaced phase viscosity increases, the influence of a dynamic contact angle on imbibition weakens, which is attributed to an increase in the viscous effect and a decrease in the frictional effect during the imbibition process. As the interfacial tension increases, the frictional effect increases, with the result that the effect of a dynamic contact angle on imbibition increases. As the capillary becomes more hydrophilic, the effect of a dynamic contact angle on imbibition becomes stronger because of a decreasing viscous effect and an increasing frictional effect. As the capillary length increases, the viscous effect increases, whereas the frictional effect decreases, leading to a decrease in the dynamic contact angle effect. As the capillary radius increases, the frictional force decreases, whereas its proportion in total resistance or the frictional effect increases, resulting in an increase in the effect of a dynamic contact angle. This work sheds light on the effect of a dynamic contact angle on capillary-liquid-liquid imbibition, including displacing phase viscosity, displaced phase viscosity, interfacial tension, capillary wettability, length, and radius. It will provide new insights into manipulating a capillary imbibition process and provide a fundamental theory for enhanced oil recovery by imbibition in conventional or unconventional reservoirs. Supplementary materials are available in support of this paper and have been published online under Supplementary Data at https://doi.org/10.2118/205490-PA. SPE is not responsible for the content or functionality of supplementary materials supplied by the authors.

Imbibition is very common, occurring in life, material, chemistry, and energy. It plays an important role in enhanced oil recovery (EOR). The development of many reservoirs is beneficial to the imbibition process, such as fractured reservoirs, conventional reservoirs developed by a water-injection mode of huff-n-puff in their later development, and unconventional reservoirs with abundant micro–nanopores developed by the fracturing technology. Here, we present a critical review of EOR through imbibition. First, the mechanisms of EOR through imbibition are reviewed, including the mechanical analysis of imbibition in a capillary, imbibition models for rocks, and the scaling law. Then, the governing factors of EOR by imbibition are summarized, including the properties of rocks and fluids and the effects of the temperature and pressure. Besides, the EOR by imbibition in the oil and gas development is discussed, including the roles of surfactants, nanofluids, salinity, shut-in time, and injection/production rates. Finally, conclusions and outlooks are presented. This review provides systematic and recent insights about EOR by imbibition and a direction for future research on this topic, which can help for a better understanding of EOR by imbibition.

The gas slippage phenomenon under dry conditions has been investigated extensively both numerically and experimentally. However, very limited research has focused on gas slippage behavior under wet conditions. Unlike conventional formation, the influence of water on the gas transport process cannot be neglected in tight formations due to the comparable amount of thin water film attached along the rock surface. It is found experimentally that the gas slippage factor is positively related to water saturation if the water saturation is small, while it decreases with water saturation if it is larger than a critical value. Most of the existing models failed to capture the measured downtrend of the gas slippage factor with increasing water saturation, which resulted from water blocking or gas trapping phenomenon. In this work, a pore-scale network model is proposed to look at the water distribution characteristic and investigate the effect of water on the gas slippage factor. The proposed pore-scale model incorporates the capillary dominated multiphase fluid distribution, real gas effect, and gas transport mechanisms at pore scale. On the basis of our pore network model, the effect of pore structure characteristics including the frequency of mean pore radius, size of mean pore radius, aspect ratio, and coordination number on the gas slippage behavior are investigated and discussed in detail. Similar to previous experimental observations, the simulated gas slippage factor shows a non-monotonic increase trend with water saturation; it starts to decrease under high water saturation, and the critical water saturation depends on the pore structure factors. It increases with the mean pore radius and coordination number but decreases with the aspect ratio. We used the pore network model to investigate the effect of the water phase on the gas slippage behavior at the pore scale for the first time. It emphasized the predominance of water blocking and the gas trapping phenomenon in the estimation of the gas slippage factor at high water saturation.

The discovery and large-scale exploration of unconventional oil/gas resources since 1980s have been considered as the most important advancement in the history of petroleum geology; that has not only changed the balance of supply and demand in the global energy market, but also improved our understanding of the formation mechanisms and distribution characteristics of oil/gas reservoirs. However, what is the difference of conventional and unconventional resources and why they always related to each other in petroliferous basins is not clear. As the differences and correlations between unconventional and conventional resources are complex challenging issues and very critical for resources assessment and hydrocarbon exploration, this paper focused on studying the relationship of formations and distributions among different oil/gas reservoirs. Drilling results of 12,237 exploratory wells in 6 representative petroliferous basins of China and distribution characteristics for 52,926 oil/gas accumulations over the world were applied to clarify the formation conditions and genetic relations of different oil/gas reservoirs in a petroliferous basin, and then to establish a unified model to address the differences and correlations of conventional and unconventional reservoirs. In this model, conventional reservoirs formed in free hydrocarbon dynamic field with high porosity and permeability located above the boundary of hydrocarbon buoyancy-driven accumulation depth limit. Unconventional tight reservoirs formed in confined hydrocarbon dynamic field with low porosity and permeability located between hydrocarbon buoyancy-driven accumulation depth limit and hydrocarbon accumulation depth limit. Shale oil/gas reservoirs formed in the bound hydrocarbon dynamic field with low porosity and ultra-low permeability within the source rock layers. More than 75% of proved reserves around the world are discovered in the free hydrocarbon dynamic field, which is estimated to contain only 10% of originally generated hydrocarbons. Most of undiscovered resources distributed in the confined hydrocarbon dynamic field and the bound hydrocarbon dynamic field, which contains 90% of original generated hydrocarbons, implying a reasonable and promising area for future hydrocarbon explorations. The buried depths of hydrocarbon dynamic fields become shallow with the increase of heat flow, and the remaining oil/gas resources mainly exist in the deep area of “cold basin” with low geothermal gradient. Lithology changing in the hydrocarbon dynamic field causes local anomalies in the oil/gas dynamic mechanism, leading to the local formation of unconventional hydrocarbon reservoirs in the free hydrocarbon dynamic field or the occurrence of oil/gas enrichment sweet points with high porosity and permeability in the confined hydrocarbon dynamic field. The tectonic movements destroy the medium conditions and oil/gas components, which leads to the transformation of conventional oil/gas reservoirs formed in free hydrocarbon dynamic field to unconventional ones or unconventional ones formed in confined and bound hydrocarbon dynamic fields to conventional ones.

Understanding and controlling the interfacial tension (IFT) of nanoconfined fluids has tremendous implications in scientific research and engineering applications. On the basis of the physical mean...

Deepwater oil and gas exploitation has become an important field in the petroleum industry development. However, there are still no mature methods for hydrate prevention in the deepwater wells clea...

A clear knowledge of fluid flow at the nanoscale will greatly contribute to recovery of unconventional oil/gas reservoirs. The distinction of nanoconfined fluid flow behavior with that of the bulk ...

Quasi-continuum water flow under highly confined conditions has tremendous applications in chemical engineering and nanotechnology. For a type of quasi-continuum flow, a bulk phase exists in the mi...

Gas mobility control is highly required to obtain a sufficiently-expanded and uniformly-developed steam chamber, which is conducive to steam-assisted gravity drainage (SAGD) production. Adding chem...

Summary A model for gas transport in nanoscale channels in shale-gas reservoirs (SGRs) is proposed using a new effective mean free path (MFP) model, which considers the effects of surface/gas interaction and the geometrical termination of a nanochannel boundary. In addition, the influences of the nanochannel dimension, formation-burial depth, surface type, and gas type on nanoconfined gas flow in slit channels are addressed. The nanoconfined gas-flow behavior is investigated for a wide range of temperature and pressure in this work because of the large prospects of shale gas in deep and ultradeep formations with pressure up to 100 MPa and temperature up to 480 K. The newly developed effective MFP model and the gas-flow-rate model are successfully validated with data from molecular dynamics (MD) simulations and experiments. Results show that the effect of surface force reduces the MFP and gas-flow capacity, which increases with a decreasing pressure, a decreasing channel size, and an increasing temperature; that the nanoconfinement effect has weaker influence on gas-transport capacity as the formation-burial depth increases and greater influence as formation pressure decreases during hydrocarbon production from SGRs; that a surface type affects the gas transport, and the gas-flow capacity in carbon (C) channels (organic channels) is stronger than that in silicon (Si) channels (inorganic channels) with the same size; and that the differences among the transport capacities of nitrogen (N2), argon (Ar), and methane (CH4) are not obvious, while the transport capacities of helium (He) are greatly lower compared with CH4 at both the SGR temperature and the laboratory temperature.

Industrial development of extra and super heavy oil as an important energy resource substitute has been achieved worldwide. Steam-assisted gravity drainage (SAGD) is one of the most important recovery methods for extra and super heavy oil reservoirs. In this review paper, the following points of SAGD have been discussed: (1) mechanism, influencing factors and application criteria; (2) field application and experimental study; (3) analytical and reservoir simulation models; and (4) current research progress and future application of multi-medium-assisted SAGD. This study gives an overview of the current status and challenges of and solutions for the SAGD technology and provides reference for the effective recovery of extra and super heavy oil reservoirs.

Solvent-Assisted Steam-Gravity Drainage (SA-SAGD) has lately been viewed as one of the most efficient alternatives to develop heavy oil reservoirs. However, there is strong evidence that reservoir ...

Summary Dual-pipe steam injection technique has currently demonstrated technical potential for improving heavy oil recovery. It can effectively delay the occurrence of steam fingering and homogenize the steam injection profile along the horizontal wellbore. In this paper, first, we built a cylindrical wellbore physical model to experimentally study the steam injection profiles of a single-pipe horizontal well and a concentric dual-pipe horizontal well. Thus, the heat and mass transfer behavior of steam along the horizontal wellbore with a single-pipe well configuration and a dual-pipe well configuration was addressed. Subsequently, considering the effect of pressure drops and heat loss, a semianalytical model for the gas/liquid two-phase flow in the horizontal wellbore was developed to numerically match the experimental observation. Next, a sensitivity analysis on the physical parameters and operation properties of a steam injection process was conducted. The effect of the injection fluid type was also investigated. Experimental results indicated that under the same steam injection condition, an application of dual-pipe well configuration can significantly enhance the oil drainage volume by approximately 35% than the single-pipe well configuration. During the experiments, both a temperature distribution and liquid production along the horizontal wellbore were obtained. A bimodal temperature distribution can be observed for the dual-pipe well configuration. From this proposed model, an excellent agreement can be found between the simulation results and the experimental data. Because of the effect of variable mass flowing behavior and pressure drops, the wellbore segment close to the steam outflow point can have a higher heating radius than that far from the steam outflow point. From the results of sensitivity analysis, permeability heterogeneity and steam injection parameters have a tremendous impact on the steam injection profile along the wellbore. Compared with a pure steam injection process, the coinjection of steam and noncondensable gas (NCG) can improve the effective heating wellbore length by more than 25%. This model is also applied to predict the steam conformance of an actual horizontal well in Liaohe Oilfield. This paper presents some information regarding the heat and mass transfer of a dual-pipe horizontal well, as well as imparts some of the lessons learned from its field operation.

Imbibition is one of the most common physical phenomena in nature, and it plays an important role in enhanced oil recovery, hydrology, and environmental engineering. For the tight reservoirs, the imbibition method has an obvious advantage in fracturing, shut-in, and huff-puff development. Although the current imbibition studies focus on oil recovery, and the inertial effect in imbibition is neglected and its mechanism is also unclear. In this paper, the inertial effect on spontaneous oil-water imbibition at micron-scale is studied by molecular kinetic theory (MKT). The frictional coefficient in the model is a fitted parameter to match the experimental data during the total imbibition process. Then, the simulation of the initial imbibition stage is conducted and the inertial effect on imbibition is identified by the difference between the model considering the inertial effect (CI) and the model neglecting the inertial effect (NI), or by the proportion of inertial force to the total resistance. Results show that (i) with an increase in the water phase viscosity, the inertial effect time shortens, maximum imbibition height and rate decrease, and thus the inertial effect on imbibition weakens; (ii) with an increase in the oil phase viscosity, the inertial effect time changes little, the maximum imbibition height and rate decrease slightly, namely, the inertial effect depends slightly on the oil phase. (iii) with an increase in the capillary wettability (hydrophilicity), the inertial effect time shortens, the maximum imbibition rate first increases and then decreases, and the inertial effect on imbibition weakens. This work sheds light on the inertial effect on oil-water imbibition by MKT, considering the effects of dynamic contact angle, water phase viscosity, oil phase viscosity, and wettabilities, which is helpful to understand the role of inertia in the oil-water or oil-fracturing fluid imbibition process.

As the most potential Carbon Capture, Utilization, and Storage (CCUS) technology, CO2-enhanced oil recovery (CO2-EOR) can both improve oil recovery and relieve the pressure of reducing CO2 emission. However, CO2-EOR projects have not been substantially deployed in China due to the significant investment and high uncertainties of technology, market, and policy. Therefore, identifying potential bottlenecks, and developing effective investment strategies are of great necessity at present. In this work, a real option approach combined with reservoir simulation technologies is proposed, which can investigate the optimal deployment timing and the investment value of the CO2-EOR projects. Meanwhile, a sensitivity analysis is conducted to examine the effects of different uncertainties. The results show that real option approach is suitable for the evaluation of CO2-EOR projects because it can fully take the flexibility of investment time into account. And it is found that under the current investment environment, it is difficult for China to deploy CO2-EOR projects on a large scale before 2030. High oil prices, low CO2 purchase prices, and transportation of CO2 by pipeline can bring forward the investment time and increase the investment value. Besides, government subsidies and technological progress are also favorable for the deployment of the project. Compared with technological progress, the effect of subsidies is more obvious, while it should be noted that huge subsidies will bring a financial burden to the government. In a word to launch CO2-EOR projects earlier and make it play a more important role in China's carbon emission reduction, a compound strategy should be made based on consideration of all these influencing factors.

The formation of hydrate will lead to serious flow assurance problems in deepwater submarine natural gas transmission pipelines. However, the accurate evaluation model of the hydrate blocking risk for submarine natural gas transportation is still lacking. In this work, a novel model is established for evaluating the hydrate risk in deepwater submarine gas pipelines. Based on hydrate growth-deposition mechanism, the mathematical model mainly consists of mass, momentum and energy conservation equations. Meantime, the model results are obtained by finite difference method and iterative technique. Finally, the model has been applied in the production of deepwater gas field (L Gas Field) in China, and the sensitivity analysis of relevant parameters has been carried out. The results show that: (a). The mathematical model can well predict the hydrate blockage risk in deepwater natural gas pipelines after verification. (b). Hydrate is easily formed at the intersection of horizontal pipeline and vertical riser, and the maximum blocking position often occurs in middle of the riser. (c). The hydrate blockage degree and length of hydrate formation region (HFR) decrease with the increase of gas transport rate. (d). The hydrate blockage degree and length of HFR decrease with the increase of gas transport temperature. (e). The hydrate blockage degree and length of HFR increase with the extension of horizontal pipeline. (f). Injecting inhibitors can effectively inhibit hydrate formation and blockage, but the improvement of transmission measures can significantly reduce the dosage of inhibitor. It is concluded that measures such as increasing gas transportation rate and temperature, shortening horizontal pipeline length, optimizing inhibitor injection point and injection rate can play a safe, economic and efficient role in hydrate preventing and controlling.

Capillary spontaneous imbibition mainly occurs in fractured reservoirs, low permeability reservoirs, and unconventional reservoirs, simultaneously accompanied by high temperature and pressure. In t...

Summary An excess adsorption amount obtained in experiments is always determined by mass balance with a void volume measured by helium (He) –expansion tests. However, He, with a small kinetic diameter, can penetrate into narrow pores in porous media that are inaccessible to adsorbate gases [e.g., methane (CH4)]. Thus, the actual accessible volume for a specific adsorbate is always overestimated by an He–based void volume; such overestimation directly leads to errors in the determination of excess isotherms in the laboratory, such as “negative isotherms” for gas adsorption at high pressures, which further affects an accurate description of total gas in place (GIP) for shale–gas reservoirs. In this work, the mass balance for determining the adsorbed amount is rewritten, and two particular concepts, an “apparent excess adsorption” and an “actual excess adsorption,” are considered. Apparent adsorption is directly determined by an He–based volume, corresponding to the traditional treatment in experimental conditions, whereas actual adsorption is determined by an adsorbate–accessible volume, where pore–wall potential is always nonpositive (i.e., an attractive molecule/pore–wall interaction). Results show the following: The apparent excess isotherm determined by the He–based volume gradually becomes negative at high pressures, but the actual one determined by the adsorbate–accessible volume always remains positive.The negative adsorption phenomenon in the apparent excess isotherm is a result of the overestimation in the adsorbate–accessible volume, and a larger overestimation leads to an earlier appearance of this negative adsorption.The positive amount in the actual excess isotherm indicates that the adsorbed phase is always denser than the bulk gas because of the molecule/pore–wall attraction aiding the compression of the adsorbed molecules. Practically, an overestimation in pore volume (PV) is only 3.74% for our studied sample, but it leads to an underestimation reaching up to 22.1% in the actual excess amount at geologic conditions (i.e., approximately 47 MPa and approximately 384 K). Such an overestimation in PV also underestimates the proportions of the adsorbed–gas amount to the free–gas amount and to the total GIP. Therefore, our present work underlines the importance of a void volume in the determination of adsorption isotherms; moreover, we establish a path for a more–accurate evaluation of gas storage in geologic shale reservoirs with high pressure.