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Results
Effects of Nano-Confinement and Heat Transfer on Phase Transition and Multi-Component Diffusion of CO2-Hydrocarbons During the Flowback and Early-Production Stages: A Field Example from a Liquid-Rich Shale Volatile Oil Reservoir
Jia, Zhihao (China University of Petroleum-Beijing, China) | Cheng, Linsong (China University of Petroleum-Beijing, China) | Cao, Chong (China University of Petroleum-Beijing, China / Sinopec Petroleum Exploration and Production Research Institute, Beijing, China) | Cao, Renyi (China University of Petroleum-Beijing, China) | Jia, Pin (China University of Petroleum-Beijing, China) | Pu, Baobiao (China University of Petroleum-Beijing, China) | Xue, Yongchao (China University of Petroleum-Beijing, China) | Ma, Ming (The Pennsylvania State University, United States)
Abstract Phase transitions of CO2-Hydrocarbons in liquid rich shale (LRS) volatile oil reservoirs after the CO2 pre-pad energized fracturing is quite obvious, particularly due to the impact of temperature changes and nano-confinement. In this paper, the impact of phase transitions caused by heat transfer and nano-confinement effects on the CO2 effective diffusion coefficient (CO2-EDC) after CO2 pre-pad energized fracturing was investigated. A novel multi-component diffusion model incorporating both heat transfer and nano-confinement effects was proposed to accurately evaluate CO2-EDC in the Gulong LRS volatile oil reservoir located in the Songliao Basin, China, which provides valuable insights into fracturing design and CO2-EOR in shale oil reservoirs. Firstly, the nano-pore network model (PNM) was constructed based on focused ion beam scanning electron microscopy (FIB-SEM). Secondly, components of oil samples were analyzed by chromatographic experiments. Then, the temperature in each pore-throat was calculated using Fourier heat transfer equations. In addition, phase states (liquid or vapor) of CO2-hydrocarbons in each pore-throat were determined by the modified PR-EOS considering nano-confinement effects, and diffusion mechanisms (Knudsen, Transition, Maxwell-Stefan diffusion) were determined by the Knudsen number. Finally, the novel PNM with multi-scale diffusion equations was established to calculate the molar flow rate, which is used to obtain CO2-EDC by solving Fick's law. The phase behavior of CO2-hydrocarbons in the nano-confined pores was investigated, and the CO2-EDC was calculated under reservoir conditions (137.5 โ, 37 MPa), and at varying injection temperatures. The results show that three distinct phase behaviors considering nano-confinement effects were observed under reservoir conditions: volatile oil in pore-throats larger than 33nm, condensate gas in pore-throats ranging from 5nm to 33nm, and wet gas or dry gas in pores/throats smaller than 5nm. However, it is only liquid in each pore-throat without considering the nano-confinement effects. As temperature increased, the phase behavior of CO2-hydrocarbons underwent a gradual transformation from a liquid state to a state of vapor-liquid coexistence, and finally to a vapor state. The phase transition is proved by the observation of a 2-month single gas production period prior to oil-gas production and a rapid decline in GOR (from 3559.7 m/m to 318.5 m/m) followed by a period of stability in the Gulong LRS volatile oil reservoir. It is worth noting that the CO2-EDC increased significantly with the nano-confinement effects, rising by 896.96% from 0 โ to 300 โ compared to an increase of 10.31% without the nano-confinement effects. Specifically, the CO2-EDC increased slowly in the liquid-dominated stage (< 180 โ) and rapidly rose in the vapor-dominated stage (> 180 โ).
- Asia > China (1.00)
- North America > United States > Texas (0.47)
- Research Report > New Finding (0.34)
- Research Report > Experimental Study (0.34)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.83)
Abstract Various transport mechanisms and phenomena unique to nanopores influence oil production from low permeability reservoirs, such as shales. One such phenomenon is the inhomogeneity of fluid properties across a pore width due to the confinement and pore wall effects. We propose a multicomponent fluid transport model for oil production from shale reservoirs by considering inhomogeneous fluid thermodynamics and transport properties based on pore-scale density distribution. We adopt the multicomponent simplified local density (MSLD) method incorporating fluid-fluid and fluid-solid interaction through the Peng-Robinson equation of state (PR-EOS) and 10-4 Lennard-Jones fluid-wall potentials to calculate density profiles in slit nanopores. Viscosity and diffusivity profiles are calculated based on the density profile. We solve a multicomponent momentum balance equation combined with the Maxwell-Stefan equation to obtain velocity profiles. We then use the area-averaged transmissibility in the multicomponent transport model based on the Maxwell-Stefan theory to simulate co- and counter-diffusion processes mimicking oil production and solvent (gas) injection processes. In addition to using the MSLD method, we employ PR-EOS and modified PR-EOS (with critical parameters shifts), representing homogenous fluid systems without and with confinement effects, to calculate thermodynamics and transport properties at pore- and continuum-scale. Porescale investigation results for a ternary hydrocarbon mixture (methane, propane, n-octane) within shale nanopores reveal that, in the case of hydrocarbon distribution in organic slit nanopores, the heaviest component exhibits a notable preference for the near-wall region due to pronounced fluid-solid interaction, while the composition in the pore-center region resembles that of the bulk fluid. Transport of the heavy component (n-octane) is enhanced at the near-wall region with a width approximately 1.5 times the fluid molecular collision diameter. Based on the deviation of the averaged mass flux ratio from unity, the pore size can be categorized into three fluid systems: inhomogeneity dominant (da < 3 nm), transition (3 nm < da < 30 nm), and homogeneity dominant (da > 30 nm) system. The fluid-wall interaction can be neglected in pores larger than 30 nm. However, fluid-solid interaction becomes increasingly significant as pores become smaller. Continuum-scale co-diffusion and counter-diffusion simulations show that, in the inhomogeneity dominant fluid system, neglecting the influence of inhomogeneous fluid results in a more than 30% overestimation of cumulative production/injection. Conversely, in the homogeneity dominant fluid systems, the impact of inhomogeneous fluid can be disregarded as the difference in cumulative production/injection is less than 1%. Furthermore, the results reveal that the commonly used modified PR-EOS incorporating critical parameter shift increases the errors associated with cumulative production and injection, resulting in even larger discrepancies between predicted and actual production/injection values. Therefore, when the fluid-wall interaction parameters are unavailable or the numerical simulations require excessive computational resources, it is advisable to utilize the PR-EOS instead of a modified PR-EOS to calculate transport coefficients and simulate fluid transport in low permeability reservoirs.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.66)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.41)
Accurate Prediction of the Saturation Pressures of Hydrocarbons in Unconventional Reservoirs: A Modified Alpha-Function for the Peng-Robinson Equation of State
Lin, Lixing (Department of Civil and Environmental Engineering, School of Mining and Petroleum Engineering, University of Alberta, Edmonton, Alberta, Canada.) | Babadagli, Tayfun (Department of Civil and Environmental Engineering, School of Mining and Petroleum Engineering, University of Alberta, Edmonton, Alberta, Canada.) | Li, Huazhou Andy (Department of Civil and Environmental Engineering, School of Mining and Petroleum Engineering, University of Alberta, Edmonton, Alberta, Canada.)
Abstract Due to the confinement and strong adsorption to the pore wall in meso- and nano- pores, fluid phase behavior in the confined media, such as the tight and shale reservoirs, can be significantly different from that in the bulk phase. A large amount of work has been done on the theoretical modeling of the phase behavior of hydrocarbons in the confined media. However, there are still inconsistencies in the theoretical models developed and validations of those models against experimental data are inadequate. In this study, we conducted a comprehensive review of experimental work on the phase behavior of hydrocarbons under confinement and analyzed various theoretical phase-behavior models. Emphasis was given to the modifications to the Peng-Robinson equation of state (PR EoS). Through the comparative analysis, we developed a modified alpha-function in PR EoS for accurate prediction of the saturation pressures of hydrocarbons in porous media. This modified alpha-function accounts for the pore size and was derived based on the regression results through minimizing the deviation between the experimentally measured and numerically calculated saturation pressure data. Meanwhile, the thermodynamic properties of propane were calculated in the bulk phase and in the nanopores. Finally, we validated the newly developed model using the experimental data generated within our research group. By applying the modified PR EoS, a more accurate representation of the experimentally measured saturation pressure data in confined nanopores was achieved. This newly developed model not only enhanced the accuracy of the predictions but also provided valuable insights into the confinement effects on the phase behavior of hydrocarbons in nanopores. Notably, we observed significant changes in the properties of propane within confined nanopores, including suppressed saturation pressure and fugacity, indicating a greater tendency for the gas to remain in the liquid phase. Additionally, the gas compressibility factor and enthalpy of vaporization were found to increase highlighting increased difficulty in transitioning from liquid to gas phase under confinement. To validate its applicability, the newly developed model was applied to the experimental data obtained in real rock samples. Interestingly, it was observed that the phase change in these samples predominantly occurred in the smallest pores. This finding highlights the importance of considering the pore size distribution when studying the phase behavior of hydrocarbons in a capillary medium even if the rock has high permeability. This study provided a simple and easy-to-implement modification to the PR EoS for accurate prediction of the phase behavior of petroleum fluids under confinement. The modification to PR EoS was more straightforward and simplified compared to the modifications available in the literature.
- North America > United States (1.00)
- North America > Canada > Alberta (0.93)
Abstract In this work, the pseudopotential lattice Boltzmann method is employed to study the phase equilibrium in confined space. The role of capillary pressure and fluid-solid interaction are evaluated separately. In the absence of solid walls, our pore-scale simulation is consistent with the thermodynamic model coupling Peng-Robinson equation of state and capillary pressure. We prove that Young-Laplace equation and Parachor model is still valid at nanoscale. When the pore space is confined by solid walls, the heterogeneous density distributions in nanopores are discovered. The decreased critical temperature and increased critical density are observed under confinement. In addition, the effect of fluid-solid interaction strength on phase behavior is studied. It is found that a larger fluid-solid force leads to a more heterogenous density distribution in nanopores. However, the average liquid/vapor density and critical temperature are not significantly affected by the strength of fluid-solid interaction. The critical pressure, on the other hand, is lower when the fluid-solid interaction is stronger. The coexistence curves and saturation pressures in nanopores with different fluid-solid force are presented which can be characterized by using contact angle. Finally, the phase behavior in a complex pore structure is calculated. This work illustrates that implementing capillary pressure or critical shift alone cannot fully describe the confined phase behavior.
Vapor-Liquid Equilibria and Diffusion of CO2/n-Decane Mixture in the Nanopores of Shale Reservoirs
Dong, Xiaohu (China University of Petroleum Beijing) | Chen, Zhongliang (China University of Petroleum Beijing) | Chen, Zhangxin (University of Calgary) | Wang, Jing (China University of Petroleum Beijing) | Wu, Keliu (China University of Petroleum Beijing) | Li, Ran (University of Calgary) | Li, Li (PetroChina Coalbed Methane Company Limited)
Abstract Numerous laboratory tests on the Northern American shale plays have observed a large number of nanopores. Because of the pore-proximity effect, the vapor-liquid phase equilibrium and transport performance of fluids in nanopores differ significantly from that observed in PVT cell. In recent years, CO2 huff-and-puff has been widely applied to unlock the shale reservoirs. But on account of the high adsorption selectivity of CO2, after the injection of CO2, the original vapor-liquid equilibria of hydrocarbons is changed. The purpose of this study is to predict the phase behavior and diffusion of the CO2/n-decane mixtures in the nanopores. The Peng-Robinson (PR) equation of state is combined with Young-Laplace equation to calculate the phase-composition diagram at the presence of capillary pressure. The equilibrium molecular dynamics simulations (MDS) are also conducted to study the phase behavior, and the number density profiles of different molecules are calculated. Then, based on the discussion of phase behavior, a series of equilibrium MDS runs are carried out to calculate the self-diffusion coefficients of CO2, n-decane, and all fluid molecules. For each MDS with a different CO2 mass fraction, the two types of fluid molecules are thoroughly mixed, the conditions of pore size and temperature are consistent with those in the phase behavior studies. Results indicate that considering the capillary pressure, when the mass fraction of CO2 is less than 40%, the bubble point suppression is more clearly shown in the phase envelope. The number density profiles of n-decane molecules show the apparent characteristics of adsorption layers. As the mass fraction of CO2 molecules increases, the self-diffusion coefficients of CO2, n-decane, and their mixtures all increase. The self-diffusion coefficients of CO2 molecules are higher than that of the n-decane molecules, and the diffusion coefficients of the entire fluid system are somewhere in between. Appropriate CO2 injection into shale oil reservoirs can not only reduce the confinement-induced bubble point suppression but also improve the flow behavior of oil in nanopores. This study can shed some critical insights for the vapor-liquid phase equilibria of confined fluids in nanopores and provide sound guidelines for the application of CO2 huff and puff in shale reservoirs.
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (3 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
Confined Behavior of Hydrocarbon Fluids in Heterogeneous Nanopores by the Potential Theory
Dong, Xiaohu (China University of Petroleum, Beijing) | Luo, Qilan (China University of Petroleum, Beijing) | Wang, Jing (China University of Petroleum, Beijing) | Liu, Huiqing (China University of Petroleum, Beijing) | Chen, Zhangxin (University of Calgary) | Xu, Jinze (University of Calgary) | Zhang, Ge (Sinopec Shengli Oilfield)
Abstract Nanopores in tight and shale reservoirs have been confirmed by numerous studies. The nanopores are not only the primary storage space of oil and gas, but also the main transport channels of confined fluids. Although considerable efforts have been devoted to study the confined behavior of hydrocarbon fluids in nanopores, most of them have a local smooth-surface assumption. The effect of pore heterogeneity is still lacking. In this paper, in order to effectively simulate the nanopore complexity, we propose the assumptions of furrowed surface and sinusoidal surface to represent the heterogeneous nanopores (or rough nanopores) in tight and shale rocks. Then, based on these assumptions, the multicomponent potential theory of adsorption (MPTA) is coupled with the Peng-Robinson equation of state (PR EOS) to investigate the behavior of hydrocarbon fluids in rough nanopores. In this theory, considering the different types of nanopore heterogeneity, the geometrical heterogeneity is modeled by a spatial deformation of the potential field, and the chemical heterogeneity is modeled by an amplitude deformation of this field. The fluid-fluid interactions are modeled by the PR EOS, and the fluid-surface interactions are modeled by a Steel 10-4-3 potential for slit-like nanopres and a modified Lennard-Jones (LJ) 12-6 potential for cylindrical nanopores. Then a prediction process for the behavior of methane, ethane, propane and their mixtures is performed. The results are compared against the experimental data of their adsorption isotherms from publishd literatures to validate the accuracy of the theory and process. Then, the effect of pore heterogeneity on the confined behavior of methane, ethane, propane is quantitatively studied. Results indicate that for the experimental data considered in this work, the theory for heterogeneous nanopores is capable of predicting the confined behavior of hydrocarbons in a wide range of pressure and temperature. The developed mathematical model can well predict the confined behavior of fluids both in slit-like and cylindrical nanopores. Compared with the results of a smooth pore surface, the geometrical heterogeneity can significantly affect the thermodynamic properties of hydrocarbon fluids, but the chemical heterogeneity cannot strongly distort the confined behavior of fluids. The effect of geometrical heterogeneity on the confined behavior of fluids mainly depends on the effective pore size. In hydrocarbon fluids, as the composition of heavy components increase, the effect of heterogeneity on the confined behavior of fluids is reduced. Also, as the nanopore size reduces, the effect of pore heterogeneity on the confined behavior of fluids is enhanced. For fluid mixture, compared with smooth surfaces, it is observed that for heterogeneous surface, the mole fraction of the heavy component in the vicinity of pore wall can increase significantly, and that of the light component is reduced. This investigation makes it possible to completely characterize the confined behavior of a confined fluid in heterogeneous nanopores.
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- (9 more...)
Modelling the Apparent Viscosity of Water Confined in Nanoporous Shale: Effect of the Fluid/Pore-Wall Interaction
Li, Jing (China University of Petroleum, Beijing & University of Calgary) | Chen, Zhangxin John (China University of Petroleum, Beijing & University of Calgary) | Lei, Zhengdong (Research Institute of Petroleum Exploration and Development) | Gao, Yan (Research Institute of Petroleum Exploration and Development) | Yang, Sheng (University of Calgary) | Wu, Wei (University of Calgary) | Zhang, Linyang (University of Calgary) | Yu, Xinran (University of Calgary) | Feng, Dong (China University of Petroleum, Beijing) | Bi, Jianfei (China University of Petroleum, Beijing) | Wu, Keliu (China University of Petroleum, Beijing)
Abstract The viscosity of nanoconfined fluid is a crucial parameter for evaluating the flow back of the fracturing fluid in unconventional reservoirs. Generally, the viscosity is an intrinsic property defined as the internal friction among fluid molecule themselves. However, the effect of the fluid/pore-wall interaction on the viscosity of fluid at the nanoscale becomes significant. Due to this strong confinement, two abnormal flow behaviors have been discovered, including an extremely high water-flow rate in hydrophobic nanotubes and an extremely slow capillary filling rate in hydrophilic nanochannels. Thus, understanding such contradictory hydrodynamics is helpful to estimate the flow performance of fracturing liquid in both organic pores and inorganic pores of shales. In this work, a concept of apparent viscosity of nanoconfined fluid is proposed, where the activation energies (indicating the energy barrier needed to be overcome for fluid motion) caused by both the fluid/ fluid interaction and fluid/pore-wall interaction are modeled. For the case with only fluid/fluid interaction, the apparent viscosity reduces to the bulk-phase viscosity, and this traditional case has been well studied. Thus, we mainly focus on the additional interaction energy caused by the pore walls during the motion of water molecules. To solve this problem, the fluid/pore-wall interaction, including an intermolecular term, an electrostatic term and a structural term, is considered to modify the Eyring's viscosity theory. Due to a repulsion term (e.g., the structural force) and an attraction term (e.g., the intermolecular force and the electrostatic force) both introduced in the surface interaction, the integrated interaction energy of fluid and pore-wall can be either positive or negative, which depends on the relative value of repulsion and attraction controlled by the pore-wall wettability. Finally, the contact angle of the pore surface is calculated by a DLVO theory (describing gas/water/solid interactions) related to the fluid/pore-wall interaction properties. The continuous viscosity profile of fluid confined inside nanochannels with different wettability and size can be directly obtained by the proposed method. Result shows that: (i) the presence of the pore-wall significantly influences the apparent viscosity of fluid. For a strongly hydrophilic channel with the contact angle approaching to zero, the average viscosity of first layer (assuming the monolayer thickness is 0.35 nm) can be 3โผ4 times higher than that of the bulk phase; whereas for a strongly hydrophobic case, the first-layer viscosity is about 2โผ3 times lower. Thus water molecules with the extremely high-viscosity close to the hydrophilic wall can be regarded as a sticking layer as the immobile state, and those with the low-viscosity near the hydrophobic wall can be regarded as the rare-density vapor due to the surface depletion effect. (ii) The average viscosity of the confined fluid is a function not only of the wettability but also of the confinement. When the pore dimension decreases to serval nanometers, the portion of water molecules in the interface region increases relative to the total water molecules present in entire nanopores, and the average viscosity is dominated by the apparent viscosity of fluids near the wall. Besides, (iii) it is worth noting that the effect of pore wall on the apparent viscosity reduces sharply, the apparent viscosity approaches to the bulk-phase viscosity when the fluid-wall distance is about 0.7-1.2 nm, corresponding to two or three molecular layers. In this work, the viscosity of the nanoconfined fluid has been successfully modeled by considering both the fluid-fluid interaction and the fluid-wall interaction. We try to pave a path for characterizing the water flow behavior in both hydrophilic and hydrophobic nanopores, and further guide to simulate the imbibition characteristic or the flowback performance of the fracturing liquid in shale gas/oil reservoirs.
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.34)
- Geology > Mineral (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.91)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
Abstract In this work, a molecular study of shale EOR is presented to elucidate some controlling parameters, such as soak time, injection pressure, and injection fluid. To create realistic structures for organic nano-porous organic structure, equilibrium molecular dynamics (EMD) is used to create channel-like geometries based on the kerogen type II structure C unit molecules prepared by Ungerer et al. 2014. The atomistic model of the oil residing on the channel is developed using a synthetic oil mixture created based on the experimental study of the phase behavior of petroleum mixtures performed by Turek et al. (1984). N2 and supercritical CO2 (sCO2) molecules are then injected into the channel at different pressures to investigate the effectiveness of this EOR mechanism by computing the oil recovery factors. In the first step, the density profiles of injected gases and synthetic oil in the pore are investigated at various injection pressures to understand the adsorption of different components. Different oil components are shown to have different adsorption tendencies to the channel surfaces. Heavier oil components, particularly C7+, have the highest adsorption tendency, denoted by an adsorption selectivity of six calculated with respect to methane, i.e., six times higher adsorption tendencies compared to methane. In the next step, simulations are performed to investigate the importance of injection pressure on the required soaking time. Soaking time is the time required to allow complete mixing of injection gas with oil. The results show that the higher sCO2 injection pressure, the more soaking time is required for the gas to be efficiently mixed with synthetic oil. Furthermore, there is an optimal soaking time after which no significant oil recovery increments can be achieved. Determining the optimal soak time has economic significance and in extreme cases can determine the faith of an EOR project. Oil recovery factors increase as injection pressures increase but the trend plateaus after reaching an inflection point (called here the minimum diffusivity pressure (MDP), similar to the minimum miscibility pressure (MMP) and minimum miscibility enrichment (MME) defined in conventional reservoirs). Next, a component-wise investigation of the recovery of oil is performed after the EOR fluids are injected. sCO2 molecules tend to be adsorbed to the surfaces of the kerogen pore by replacing (desorbing) the molecules of oil. This phenomenon takes place faster for the lighter oil components compared to the heavier ones. The computed oil recovery factors range from 24 to 49%, which is consistent with the experimental measurements in Jin et al. (2017). The fraction of the heavier components in the recovered oil is smaller than the lighter components especially when N2 is injected as the EOR fluid (maximum 20 and 34% for N2 and sCO2 injection, respectively). A comparison of the oil recovery factors between sCO2 and N2 shows the superiority of the former as the EOR fluid. This is attributed to sCO2 molecules possessing higher diffusivity in oil and also higher adsorption tendencies to the kerogen atoms on the channel walls compared to N2 molecules. This work is one of the few studies on the shale EOR at the molecular level. This work along with the extensions of this work to larger scales can shed light on the highly unknown and complex nature of shale recovery.
- North America > United States > North Dakota (0.29)
- North America > United States > Montana (0.29)
- North America > United States > Texas (0.28)
- Research Report > New Finding (0.87)
- Research Report > Experimental Study (0.54)
- Geology > Geological Subdiscipline (0.88)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.68)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- (33 more...)
- Reservoir Description and Dynamics > Reserves Evaluation > Recovery factors (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
Abstract Shale reservoirs are estimated to account for approximately 10-30% of oil and gas worldwide, yet operators rarely produce more than 10% of the original hydrocarbons in place from them. These poor production numbers are a result of the assumption that the same pressure-volume-temperature (PVT) analysis procedures that are employed in conventional reservoirs are also applicable to shale and tight reservoirs. However, traditional PVT analysis does not account for the nanoporosity of the shale and, therefore, neglects the ability of nanopores to significantly alter the phase behavior of reservoir fluids. To quantify the effects of shale nanoporosity on the phase behavior of reservoir fluids, a novel gravimetric apparatus was developed. Unlike other gravimetric apparatuses in the literature, ours is compatible with both simple and complex experimental fluids and up to several hundred grams of unconsolidated or consolidated porous media at temperatures and pressures up to 232แตC and 5,000 psi, respectively. Furthermore, our apparatus does not require a buoyant force correction, which is one of the major shortcomings of most commercially available gravimetric apparatuses. These unique features allow us to study fluid phase behavior in shale and tight cores with high accuracy and efficiency. In the course of an exhaustive three-year research program, we have used this apparatus to measure the first capillary condensation isotherm for a fluid mixture with more than two components and discovered new phenomena of capillary condensed and supercritical fluids in the nanopores of shale rock and synthetic porous media. By reviewing the works produced over the course of this research, we are now able to answer longstanding questions as to when and how nanoconfinement-induced phase behavior occur in shale reservoirs and the implications that different types of phase behavior, including capillary condensation and nanoconfined supercriticality, have for oil and gas production.
Effects of Confinement on Compositional Simulation in Shale Reservoirs with Thermodynamic Properties Upscaling from Pore- to Reservoir-Scale
Cui, Xiaona (Texas A&M University and Northeast Petroleum University) | Song, Kaoping (China University of Petroleum - Beijing) | Yang, Erlong (Northeast Petroleum University) | Jin, Tianying (Texas A&M University) | Huang, Jingwei (Texas A&M University) | Killough, John (Texas A&M University) | Dong, Chi (Northeast Petroleum University)
Abstract The phase behavior shifts of hydrocarbons confined in nanopores have been extensively verified with experiments and molecular dynamics simulations. However, the impact of confinement on large-scale reservoir production is not fully understood. This work is to put forward a valid method to upscale the pore-scale fluid thermodynamic properties to the reservoir-scale and then incorporate it into our in-house compositional simulator to examine the effect of confinement on shale reservoir production. Firstly, a pore-scale fluid phase behavior model is developed in terms of the pore type and pore size distribution (PSD) in the organic-rich shale reservoir using our modified Peng-Robinson equation of state (PR-C EOS) which is dependent on the size-ratio of fluid molecule dynamic diameter and the pore diameter. And the fluid composition distribution and PVT relation of fluids in each pore can be determined as the thermodynamic equilibria are achieved in the whole system. Results show that the initial fluid composition distribution is not uniform for different pore types and pore sizes. Due to the effect of confinement, heavier components are retained in the macropore, and lighter components are more liable to accumulate in the confined nanopores. Then an upscaled equation of state is put forward to model the fluid phase behavior at the reservoir-scale based on our modified PR-C EOS using a pore volume-weighted average method. This upscaled EOS is validated with the pore-scale fluid phase behavior simulation results and can be used for compositional simulation. Finally, two different reservoir fluids from the Eagle Ford organic-rich shale reservoir are simulated using our in-house compositional simulator to investigate the effect of confinement on production. In addition to the critical property shift which can be described by our upscaled PR-C EOS, capillary pressure is also taken into account into the compositional simulation. Results show that the capillary pressure has different effects on production in terms of the fluid type, leading to a lower producing Gas/Oil ratio (GOR) for black oil and a higher GOR for gas condensate. Critical property shift has a consistent effect on both the black oil and gas condensate, resulting in a lower GOR. It should be noted that the effect of capillary pressure on production is suppressed for both fluids with the shifted critical property.
- North America > United States > Texas (1.00)
- North America > Canada (0.94)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- (10 more...)