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Summary A computational method using molecular-simulation data is introduced to estimate the average mean-free-path length of multicomponent hydrocarbon molecules in an organic nanochannel. Grand-canonical Monte Carlo (MC) simulation is used first to construct the equilibrium distribution of the gas molecules in the channel. These results show that the smaller the channel is, the denser the gas mixture becomes because of nanoconfinement effects. Capillary condensation occurs in the smaller channels. The fluid composition inside a channel becomes progressively heavier when the bulk-fluid pressure outside the nanopore is reduced and the lighter hydrocarbons leave the channel. The average length of the confined molecules is estimated to be an order of magnitude smaller than the theoretical value. Further, the length does not show a strong dependence on the channel width and the pressure. Consequently, the predicted Knudsen-number value does not vary significantly, as anticipated by the kinetic theory of gases and by the molecular simulations of pure fluids. This invariance indicates that compositional change caused by nanoconfinement eliminates transition into other transport regimes where continuum mechanics is no longer valid. Introduction Mean free path is a fundamental quantity that relates to various physical properties of ideal-gas molecules, such as density, viscosity (Arlemark et al. 2010; Dongari et al. 2011a, 2011b), and molecular-diffusion coefficient (Taylor and Krishna 1993). In microfluidics and nanofluidics, the mean-free-path length is often used to determine the dominant transport mechanism of the rarefied gas molecules in microchannels and nanochannels (Karniadakis et al. 2005). These studies have recently been extended to understand natural-gas transport in nanopores in source rocks such as shale (Civan 2010; Freeman et al. 2011). Because of their unique environment of deposition and burial, diagenesis, and hydrocarbon-fluid generation, the source rocks maintain confined pore structures in clays, solid bitumen, and kerogen. Various groups have investigated the physical and chemical properties of the hydrocarbon fluids and water under the effects of nanoconfinement (Javadpour et al. 2007; Freeman et al. 2011; Kang et al. 2011; Ambrose et al. 2012). Kerogen, an insoluble organic constituent of the source rock, has in particular received much interest because of its nanopores with a large specific surface area contributing to the storage of the hydrocarbon fluids.
Baek, Seunghwan (Texas A&M University) | Akkutlu, I. Yucel (Texas A&M University) | Lu, Baoping (Sinopec Research Institute for Petroleum Engineering) | Ding, Shidong (Sinopec Research Institute for Petroleum Engineering) | Xia, Wenwu (Harding Shelton Petroleum Engineering & Technology Limited)
Routine history-matching and reservoir calibration methods for horizontal wells with multiple hydraulic fractures are complex. Calibration of important fracture and matrix quantities is, however, essential to understand the reservoir and estimate the future recoveries. In this paper, we propose a robust method of simulation-based history-matching and reserve prediction by incorporating an analytical solution of production Rate Transient Analysis (RTA) as an added constraint. The analytical solution gives the fracture surface area contributing to the drainage of the fluids from the matrix into the fractures. The surface area obtained from the RTA is the effective area associated with the production—not total area. It is the most fundamental and the most significant quantity in the optimization problem. Differential evolution (DE) algorithm and a multi-scale shale gas reservoir flow simulator are used during the optimization. We show that the RTA-based optimization predicts the quantities related to completion design significantly better. Further, we show how the estimated total fracture surface area can be used to measure the hydraulic fracturing quality index, as an indication of the quality of the well completion operation. The most importantly, we predict that the fractures under closure stress begin to close much sooner (100 days) than the prediction without the RTA-based fracture surface area constraint. The deformation continues under constant closure stress for about 20 years, when the fractures are closed nearly completely. This work attempts to use the traditional reservoir optimization technologies to predict not only the reserve but also the life of the unconventional well.
Summary Significant research has been conducted on hydrocarbon fluids in the organic materials of source rocks, such as kerogen and bitumen. However, these studies were limited in scope to simple fluids confined in nanopores, while ignoring the multicomponent effects. Recent studies using hydrocarbon mixtures revealed that compositional variation caused by selective adsorption and nanoconfinement significantly alters the phase equilibrium properties of fluids. One important consequence of this behavior is capillary condensation and the trapping of hydrocarbons in organic nanopores. Pressure depletion produces lighter components, which make up a small fraction of the in-situ fluid. Equilibrium molecular simulation of hydrocarbon mixtures was carried out to show the impact of CO 2 injection on the hydrocarbon recovery from organic nanopores. CO 2 molecules introduced into the nanopore led to an exchange of molecules and a shift in the phase equilibrium properties of the confined fluid. This exchange had a stripping effect and, in turn, enhanced the hydrocarbon recovery. The CO 2 injection, however, was not as effective for heavy hydrocarbons as it was for light components in the mixture. The large molecules left behind after the CO 2 injection made up the majority of the residual (trapped) hydrocarbon amount. High injection pressure led to a significant increase in recovery from the organic nanopores, but was not critical for the recovery of the bulk fluid in large pores. Diffusing CO 2 into the nanopores and the consequential exchange of molecules were the primary drivers that promoted the recovery, whereas pressure depletion was not effective on the recovery. The results for N 2 injection were also recorded for comparison. Introduction Resource shale and other source rock formations, such as mudstone, siltstone, and carbonates, have significant amounts of organic material that makes up a complex multiscale pore structure that not only consists of fractures and microcracks but also nanometer-sized organic pores (Loucks et al. 2012). In particular, as a solid insoluble organic material, kerogen has received substantial interest owing to its capability to store hydrocarbons (Javadpour et al. 2007; Kang et al. 2011; Ambrose et al. 2012; Bousige et al. 2016). The amount of organic matter is directly correlated to the amount of hydrocarbons stored in place.
Summary Source rocks, such as organic-rich shale, consist of a multiscale pore structure that includes pores with sizes down to the nanoscale, contributing to the storage of hydrocarbons. In this study, we observed hydrocarbons in the source rock partition into fluids with significantly varying physical properties across the nanopore-size distribution of the organic matter. This partitioning is a consequence of the multicomponent hydrocarbon mixture stored in the nanopores, exhibiting a significant compositional variation by pore size-- the smaller the pore size, the heavier and more viscous the hydrocarbon mixture becomes. The concept of composition redistribution of the produced fluids uses an equilibrium molecular simulation that considers organic matter to be a graphite membrane in contact with a microcrack that holds bulk-phase produced fluid. A new equation of state (EOS) was proposed to predict the density of the redistributed fluid mixtures in nanopores under the initial reservoir conditions. A new volumetric method was presented to ensure the density variability across the measured pore-size distribution to improve the accuracy of predicting hydrocarbons in place. The approach allowed us to account for the bulk hydrocarbon fluids and the fluids under confinement. Multicomponent fluids with redistributed compositions are capillary condensed in nanopores at the lower end of the pore-size distribution of the matrix ( 10 nm). The nanoconfinement effects are responsible for the condensation. During production and pressure depletion, the remaining hydrocarbons become progressively heavier. Consequently, hydrocarbon recovery from these small pores is characteristically low. Introduction Resource shale and other source-rock formations with significant amounts of organic matter, such as mudstone, siltstone, and carbonate, have a multiscale pore structure that includes fractures, microcracks, and pores down to a few nanometers (Ambrose et al. 2012; Loucks et al. 2012). The total amount of hydrocarbons stored is directly proportional to the amount of organic matter. Therefore, extensive studies regarding hydrocarbon storage in the organic matter inside source rocks have been conducted to investigate the effects of the amount, type, and thermal maturity of the organic matter, as well as the moisture content and swelling strain (Weniger et al. 2010; Gasparik et al. 2012; Modica and Lapierre 2012; Zhang et al. 2012; Chen and Jiang 2016). Simple pore models with organic walls, such as slit pores with graphite walls, have been widely used, with a focus on providing new insights into fluid storage at the microscopic scale (Ottiger et al. 2008; Adesida et al. 2011; Ambrose et al. 2012; Mosher et al. 2013; Li et al. 2014). Cristancho-Albarracin et al. (2017) showed that a 4-nm pore contains roughly 50% adsorbed hydrocarbons, depending on the reservoir pressure and temperature.
Organic matter in source rocks stores oil in significantly larger volume than that based on its pore volume due to so-called nanopore confinement effects. However, during production and depletion, recovery of that oil is low. In this paper, we introduce the nano-confinement effects and explain their impact on the release of oil molecules. We propose to control these effects and increase the oil recovery using lean gas injection, such as ethane or carbon-dioxide. We identify and discuss microscopic-level oil recovery mechanisms that appear during the soaking and production stages.
Due to the nature of the problem, molecular Monte Carlo simulation method is used for the investigation. A multi-component hydrocarbon mixture is considered in model organic pores under reservoir conditions. The fluids stored in pores are in thermodynamic equilibrium with a nearby bulk fluid in a fracture. The fluid composition in pores varies with the size of the pore and becomes progressively heavier during the production as the bulk fluid pressure is reduced. The lean gas molecules are introduced to the nanopores by adjusting the bulk fluid composition and pressure to the desired values. Simulations are used to predict fate of in-situ and the injected molecules when the system is reached to equilibrium.
Results show that oil in smaller nanopores is richer in heavy components compared to the bulk oil outside in the micro-crack. Compared to gas reservoirs, the impacts of the nano-confinement on in-place fluid volume is not significant. Recovery of the confined oil is typically below 15 % indicating that pressure depletion and fluid expansion is no longer an effective recovery mechanism. Ethane injection shows higher recovery performance than CO2 injection; it improves recovery up to 90 %, depending on its composition in the fracture. Ethane recovers 5-20 % higher than carbon dioxide in both large pores and nanopores, because ethane molecules are more effective in vaporizing the heavier molecules in the pore. In addition, ethane reduces viscosity of the confined oil, and its diffusion is faster than CO2. In summary, lean gas injection is effective in recovering the oil but its delivery to the matrix using fractures and micro-cracks under closure stress makes injection operations challenging in the field.
Much work has been done targeting hydrocarbon fluids in organic materials of source rocks such as kerogen and bitumen. These were, however, limited in scope to simple fluids confined in nanopores and ignored multi-component effects. Recent studies using hydrocarbon mixtures revealed that compositional variation caused by selective adsorption and nano-confinement significantly alters the fluids phase equilibrium properties. One important consequence of this behavior is capillary condensation and trapping of hydrocarbons in nanopores. Fluid expansion is not an effective mechanism in these pores. To show the impact of lean gas injection on the hydrocarbons recovery, an investigation is carried out using equilibrium molecular simulations of hydrocarbon mixtures with varying concentrations of CO2. The results with N2 are also presented for comparison. We show that large molecules in the mixture are left behind in nanopores are generally responsible for the residual hydrocarbon amount, and that high-pressure CO2 injection extracts more hydrocarbons from the nanopores than that based on pressure depletion only. In these small pores, the injection pressure and the kind of injected gas play a critical role in recovery. We also show that the nanopore surface area, rather than the nanopore size, is the primary factor affecting the residual amount. CO2 molecules introduced into the nanpores during the soaking period of a cyclic injection operation lead to exchange of molecules and a shift in the phase equilibrium properties of the confined fluids. This exchange has a stripping effect and in turn enhances the hydrocarbons recovery. However, the subsequent production and pressure depletion has no additional impact on the recovery beyond the stripping effect. CO2 injection and soaking has the ability to extract the heavier hydrocarbon fluids irrespective of the operating pressure conditions, while the pressure depletion produces the lighter fluids from the nanopores.
Akkutlu, I. Yucel (Texas A&M University) | Baek, Seunghwan (Texas A&M University) | Olorode, Olufemi M. (Texas A&M University) | Wei, Pang (Sinopec Research Institute of Petroleum Eng.) | Tongyi, Zhang (Sinopec Research Institute of Petroleum Eng.) | Shuang, Ai (Sinopec Research Institute of Petroleum Eng.)
Organic-rich shale formations consist of multi-scale pore structure, which includes pores with sizes down to nano-scale, contributing to the storage of hydrocarbons. In this paper, we show that the hydrocarbons in the formation partition into fluids with significantly varying physical properties across the nanopore size distribution of shale. This partitioning is a consequence of multi-component hydrocarbon mixture stored in nanopores showing a significant compositional variation with the pore size. The smaller the pore is, the heavier and the more viscous the hydrocarbon mixture becomes. During the production and pressure depletion, primarily the lighter hydrocarbons of the mixture are released from the nanopores. Hence, the composition of the remaining hydrocarbons inside the pores becomes progressively heavier. The viscosity and apparent molecular weight of the hydrocarbon mixture left behind increase significantly during the depletion. The kinetic mean-free path length of the mixture does not increase, however, as anticipated from the kinetic theory of gases. Further, the length may decrease drastically in small nanopores as an indication of capillary condensation and trapping of the hydrocarbon mixture. These effects significantly limit the release of hydrocarbons from nanopores, in particular those pores with sizes smaller than 10nm.
In the light of these microscopic scale observations, the concept of composition redistribution of the produced fluids is introduced and a new volumetric method is presented honoring the compositional variability in nanopores for an improved accuracy in predicting hydrocarbons in-place in presence of adsorption and nano-confinement effects. The method allows us to differentiate mobile bulk hydrocarbon fluids from the fluids under confinement effects and from the trapped hydrocarbon fluid dissolved in the organic material. Hence, it also reduces the uncertainties in predicting the reserve. The application of the method is presented using produced hydrocarbon fluid composition for dry gas and wet-gas formations and using reservoir flow simulation of production from a multi-stage fractured single horizontal well. We showed that liquids production is mainly due to flow of bulk fluid in large-pore volume.