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Fan, Dian (University College London) | Wang, Wendong (China University of Petroleum, East China) | Ettehadtavakkol, Amin (Texas Tech University) | Su, Yuliang (China University of Petroleum, East China)
Molecular Dynamics (MD) simulation has been helpful to study liquid transport through simple pore structures, e.g., single straight pores. However, to study the overall flowing capability through a porous medium, e.g., shale rocks, heterogeneities should be considered at the Representative Elementary Volume (REV) scale. We propose an analytical permeability model for liquid through a nanoporous REV by accounting for the heterogeneity, tortuosity, and wettability features.
We model oil slippage and adsorption in hydrophobic pores and hydrophilic pores to investigate the apparent slippage phenomenon in the mix-wet porous media. The fractal theory is applied to characterize REV-scale heterogeneities including pore size distribution, pore-throat tortuosity, and pore surface roughness. We particularly modify the classical slippage factor by a fractal tortuosity to study liquid slippage through tortuous pores by using MD data for straight nanotubes.
The proposed model gives an insight to liquid transport mechanisms in nanoporous and heterogeneous porous media and contributes to understanding hydrocarbon production in tight reservoirs at field scales. The results show two competing impacts of pore confinement. 1) The apparent oleic slippage is the result of liquid-solid interactions, and more importantly, the pore confinement's effect. Oil can slip in hydrophobic organic pores evidently, quantitatively comparable to oil slippage in hydrophilic inorganic pores, due to a higher pore-throat tortuosity and a smaller pore size. 2) The apparent oil permeability is the result of intrinsic permeability and apparent slippage. Despite a comparable slippage factor in both organic and inorganic pores, the apparent permeability in organic matter is restricted by stronger pore confinement.
In the past decade, researchers have been actively investigating flow behaviors of fluids in carbon nanotubes (CNTs) (Striolo, 2006; Ho, 2017). Flow enhancement and liquid (e.g., water and oil) slippage through CNTs are commonly observed under experimental conditions, where the apparent flow velocity is several orders of magnitude higher than that predicted by the classical Hagen-Poiseuille equation (de Gennes, 2002; Whitby and Quirke, 2007; Joseph and Aluru, 2008; Myers, 2011; Podolska and Zhmakin, 2013).
Crandall, Dustin (National Energy Technology Laboratory) | Gill, Magdalena (National Energy Technology Laboratory, LRST) | Moore, Johnathan (National Energy Technology Laboratory, LRST) | Brown, Sarah (West Virginia Geological and Economic Survey) | Mackey, Paige (National Energy Technology Laboratory, ORISE)
The behavior of fractured low-permeability rock in many subsurface formations is critical for unconventional resource extraction. Understanding how flow through individual fractures changes during shearing, and what influence heterogeneity of the rock has on shearing behavior, was the focus of our laboratory study. Computed tomography (CT) scanning of fractured rocks undergoing shear was coupled with numerical simulations of fluid flow through these fractures. We sheared multiple cores from the Marcellus and Eau Claire shales in a closed system with confining pressures of greater than 1000 psi. Samples were manually sheared in a step wise fashion. After each shearing event we assessed the bulk hydrodynamic response by measuring permeability through the core and performed a high-resolution CT scan to understand how the principal and secondary fractures were changing in the core volume. The mineralogy of each sample was examined via x-ray fluorescence.
A range of interdependent characteristics influence fracture network evolution and sample cohesion: mineralogy, lithological heterogeneity, principal fracture morphology, fracture asperities, and shearing direction in relation to bedding. We found that samples sheared parallel to bedding were less likely to develop extensive networks of secondary fractures, with secondary fracture growth contingent on the presence of large asperities. Fracture permeability tended to increase with continued shear and secondary fracture development, but a high variance existed between samples. In some instances, permeabilities decreased in response to shear-initiated aperture reduction due to fracture mating. Gouge formation is another factor contributing to the transmissivity decreases, particularly in shale-dominated fracture regions. The ability to study this complex behavior in a controlled fashion using CT scanning enables a view into processes that impact production in many unconventional formations. Findings show that small scale features and details can play a significant role in fracture behavior and should be accounted for.
Shale properties vary significantly and understanding how fractures evolve due to geomechanical stressing can improve our understanding of how to effectively stimulate a variety of formations.While hydraulic fracturing is a large-scale activity, the microfabric and heterogeneity of shale can control fracture evolution and flow properties. Upscaling the impact of microfabric and heterogeneity is poorly captured in most modeling and planning efforts; this disconnect between small scale features and large-scale operations is understandable. It is difficult to measure changes in fractures directly, difficult to implement upscaled equations of value, and difficult to know if studied laboratory/outcrop samples are representative of activities in the subsurface. This study describes the observed behavior of two distinctly different shales under controlled geomechanical stressing to examine what impact small features have on fracture evolution. By examining two shales with distinctly different structure and composition our goal is to understand when inclusions of micro-features in upscaling is critical to understanding system dynamics.
ABSTRACT: Hydraulically stimulating dense reservoirs to extract Oil and Gas (O&G) will remain the preferred technology in shale resource development. Fluid is injected into a well and as the pressure increases, the rock mass fractures, leaving residual increased fluid conductivity along the stimulated natural fractures, increasing formation permeability so that slow diffusive O&G escape from tiny pores can take place at commercially interesting rates. The Hydraulic Fracturing (HF) design process is a complex mechanical interaction analysis based on the Geology of the rocks and the Geometry of the HF fractures or stimulated volume - G&G interactions. Stress is the primary control (work minimization) and if the fracture size (height) is large, or if fracturing is taking place in multi-layered strata with lateral stress inhomogeneity, the geometry of the stimulated zone for a HF stage - height, length, and spatially averaged aperture changes - is impacted by the initial and induced stress profile. This paper attempts to somewhat clarify the outcomes for a single fracture stimulation in a homogeneous 2D elastic medium with non-uniform stresses at the boundaries.
Hydraulic Fracture Stimulation (HFS) is the most effective technique to extract Oil and Gas (O&G) from low-permeability formations. Similar to all other stimulation techniques, the goal of HFS is to increase the reservoir permeability, connect natural and induced fractures and ultimately, increase the productivity of the reservoir to enhance O&G profitability (Daneshy, 2010).
Hydraulic Fracturing (HF) is a multi-disciplinary process (Taleghani et al, 2015), and is acclaimed as the most effective reservoir-scale stimulation technique. To attain economical production rates from tight strata such as milliDarcy range sandstones to microDarcy range shale oil and shale gas (Al-Kanaan, 2014), HF is applied along long horizontal wells in stages. A full well stimulation may cost one to two million dollars per well, more for exceptional cases (high pressures, large volumes, complex treatment schedules, many stages). The design and operational processes involved in HF are complex and include hydraulic, mechanical, geomechanical and logistics aspects, requiring a comprehensive workflow. HF design must address geomechanical (in-situ state) and production aspects (experience) in advance, and for optimization, it is also necessary to monitor and evaluate the success of the HFS (Cantagliari et al., 2010). Furthermore, preliminary workflows for HFS can be enhanced by including other concerns and recommendations arising from environmental, economic, social, and related issues (Oyarhossein & Dusseault, 2016).
Hydraulic fracturing has been widely used for unconventional reservoirs including organic-rich carbonate formations for oil and gas production. During hydraulic fracturing, massive amount of fracturing fluids are pumped to crack-open the formation and only a small percentage of the fluid is recovered during the flowback process. The negative effects of the remaining fluid on the formation such as clays swelling and reduction of rock mechanical properties have been reported in literatures. However, effects of fluids on source rock properties, especially the microstructures, porosity and permeability, are scarcely documented. In this study, microstructure and mineralogy changes induced in tight carbonate rocks by imbibed fluids and corresponding changes in permeability and porosity are reported.
Two sets of tight organic-rich carbonate source rock samples were examined. One sample set was sourced from the Middle East field and the other was an outcrop from Eagle Ford Shale that is considered to be analogous to the one from the Middle East field. Three fracturing fluids, namely 2% KCl, 0.5 gpt slickwater and synthetic seawater, were used to treat the thin-section of the source rock and core samples. Modern analytical techniques such as SEM and EDS were used to investigate the source-rock morphology and mineralogy changes prior and after the fluid treatment at micron-scale level. Porosity and permeability as a function of confining pressures were quantified on core samples to investigate changes in flow properties due to the fracturing fluids treatments.
The SEM and EDS results prior to and after fracturing fluid treatments on the source rock samples showed the microstructural changes in all three fluids. In 2% KCl and slickwater fluid, reopening of some mineral-filled natural fractures was observed. The enlargement of micro-fractures was slightly more noticeable for samples treated with 2% KCl in comparison to slickwater at the micron-scale level. In one sample, dissolution of organic matters was captured in slickwater fluid treated rock sample. Some mineral precipitation and new micro-fractures generation were observed for samples treated with seawater. The new micro-fractures generation and mineral dissolution through the fluid treatment would result in the increases in both porosity and permeability, while the mineral deposition would result in permeability decrease. The overall increase in absolute gas permeability was quantified by the experimental measurements under different effective stresses for the core plug samples. This effect on absolute gas permeability increase has an important implication for hydrocarbon recovery from unconventional reservoirs.
This study provides experimental evidences at different scales that aqueous-based fracturing fluid may potentially have positive effect on gas production from organic-rich carbonate source rock by increasing absolute gas permeability through mineral dissolution and generation of new or re-opening of old microfractures. This observation will be beneficial to the future usage of fresh and seawater based fluids in stimulating gas production for organic-rich carbonate formations.
Liang, Feng (Aramco Services Company: Aramco Research Center) | Lai, Bitao (Aramco Services Company: Aramco Research Center) | Zhang, Jilin (Aramco Services Company: Aramco Research Center) | Liu, Hui-Hai (Aramco Services Company: Aramco Research Center) | Li, Weichang (Aramco Services Company: Aramco Research Center)
Carbonate reservoirs dominate 70% of oil and 90% of gas reserves in Middle East region, and imbibition is the main mechanism for fracturing fluid up-take during hydraulic fracturing stimulation process. Due to highly heterogeneous nature of tight carbonate source rocks, it is crucial to understand effects of the imbibed fluid on the mechanical, morphological and flow properties of the carbonate rocks. While the influence of imbibed fluids on the wettability of carbonate reservoir has been studied intensively, the research on effects of imbibed fluids on the texture and mineralogy of the carbonate rocks is very limited. This paper aims to provide a conceptual approach and workflow to characterize and quantify microstructure and mineralogy changes resulting from the imbibed fluids.
A thin-section of low permeability organic-rich carbonate rock sample with a dimension of 7mm × 7mm × 0.3mm (length × width × thickness) was used in the study. The sample was submerged into 2% KCl (pH = 7.1) fluid from one end to simulate the spontaneous imbibition process. Scanning Electron Microscope (SEM) was used to capture the sample’s morphological change before and after spontaneous imbibition. Energy Dispersive Spectroscopy (EDS) mapping was used to study mineralogy changes (dissolution and precipitation) before and after fluid treatment. Inductively coupled plasma (ICP) equipped with optical emission spectrometer (OES) detector has been used to quantify dissolved ion concentrations in the treatment fluid. Permeability and porosity were measured using core plugs (1" in diameter × 1.5" in length) before and after imbibition process with half-length of the sample submerged into the treatment fluid.
The SEM images for the thin-section sample show three zones with distinct fluid up-take characters. In Zone I, which was submerged into the testing fluid, considerable mineral dissolution has been observed. In Zone III, which was above the testing fluid level, considerable mineral precipitation was detected. While in the transition zone (Zone II, which was between the above two zones around the water-air level), minor amount of mineral dissolution was observed. The mineralogy changes resulting from the dissolution and precipitation have been identified by EDS analysis in all three zones. Gypsum and calcite were found to be dissolved in the imbibed fluids, while gypsum was found to be deposited on the rock surface in zones above fluid level. The observed gypsum deposition might result from the dissolution of the gypsum and calcite and re-precipitaion later from the imbibition experiment due to water evaporation and/or from sample drying process. Absolute permeability and porosity measurements for core plug samples show that both increased after the imbibition process.
We assert that a classification of gas flow regimes in shales that is widely accepted in the petroleum industry, may be inconsistent with the physics of high-pressure gas flow in capillaries. This classification follows from the 1946 work by
In the small-scale, low-velocity flows of gases, failure of the standard Navier-Stokes description (the standard Darcy law in petroleum engineering) can be quantified by the Knudsen number, ratio of the mean free path, λ, of gas molecules at the reservoir pressure and temperature to the characteristic pore radius,
For example, in Barnett mudrocks, naturally occurring pores are predominantly associated with organic matter and pyrite framboids. In organic matter, the median pore length is 100 nm,
The generally accepted "Knudsen-diffusion" in shales is based on a mistranslation of the flow physics and may give theoretically unsound predictions of the increased permeability of shales to gas flow. This increase of permeability is real, and it comes from the micropores, fine-scale microfractures and cracks. The nanopores in shales provide gas storage by sorption and capillary condensation of heavier gas components. In the smallest nanopores even methane molecules are increasingly ordered and resemble more liquid than gas. These nanopores feed the macroscopic flow paths in ways that are not captured well by the generally accepted equations.
Understanding carbon dioxide flow behavior and storage capacity in shale reservoirs is important for both carbon dioxide related improved oil recovery (IOR)/enhanced gas recovery (EGR) performance and carbon sequestration. However, the literature lacks experimental database of simultaneously and continuously measuring carbon dioxide permeability and storage capacity in shales under a wide range of pressures. In this study, we aim to fill this gap by investigating and comparing carbon dioxide transport mechanisms in shales under low pressure and high pressure conditions. Forty pressure pulse transmission tests were performed with carbon dioxide and other two types of gas (helium and nitrogen) for comparison. Tests were conducted under constant effective stress (2,000 psi) with multistage increased pore pressures (0~2,000 psi). Gas (carbon dioxide and nitrogen) adsorption capacity was measured using the difference between the total gas volume and the free gas volume, in terms of both Gibbs and absolute adsorption. Afterward, gas apparent permeability including diffusion/slip-flow/Darcy-flow/adsorption was calculated, and an analytical solution for adsorption free permeability determination was used to evaluate adsorption contribution to flow capacity. The experimental observations indicate that CO2 petrophysical properties differ significantly from other types of gas in shale reservoirs. Its adsorption and apparent permeability all decline markedly across the phase change region, leading to the ultra-low permeability in the high-pressure region.
CO2 injection has been suggested as a feasible method for IOR in tight oil or shale oil reservoirs by conventional flooding or huff-n-puff process (Ren et al. 2010; Willhite et al. 2012; Afonja et al. 2012; Jin et al. 2016a; Jin et al. 2016b; Hawthorne et al. 2017; Jia et al. 2017a). Also, CO2 has stronger adsorption capacity than CH4 in shale reservoirs, making it promising to recover CH4 through competitive adsorption in shale gas reservoirs (Clarkson and Haghshenas 2013; Aljamaan 2013). On the other hand, injecting CO2 into shales reduces greenhouse emissions and may help alleviate climate change (IEA, 2016). Therefore, a deep understanding of CO2 adsorption and flow behavior is critical for both field operation and accurate modelling of IOR and EGR processes.
Li, Jing (China University of Petroleum at Beijing) | Jia, Pin (China University of Petroleum at Beijing) | Wu, Keliu (China University of Petroleum at Beijing) | Wang, Xiangzeng (Shaanxi Yanchang Petroleum Group Corp. Ltd.) | Qu, Shiyuan (China University of Petroleum at Beijing) | Shi, Juntai (China University of Petroleum at Beijing) | Jiang, Tianhao (CNOOC EnerTech-Drilling & Production Co.) | Dong, Yifu (CNOOC EnerTech-Drilling & Production Co.)
Characteristics of gas transport in nanopores are topics of great interest for evaluation of unconventional reservoirs. The apparent permeability model for single-phase gas flow has been extensively investigated. Few models, however, have been established for the gas transport in gas/water two-phase flow condition. Unfortunately, initial water always exists under reservoir condition. Although the initial water saturation is generally regarded as immobile state, its impact on gas flow capacity should not be simply neglected. In this work, firstly, the state of sub-irreducible water saturation in shale gas reservoirs have been carefully investigated, and the thickness of thin film bound on inorganic pore surface (e.g. clay or quartz) has been quantified. Subsequently, by considering the impact of the water film on the effective hydraulic diameter, gas diffusion-slip-flow model is established. Noting that the intermolecular interactions of gas phase at high pressure and temperature condition become remarkable, the real gas effect is also considered rather than regarding shale methane as ideal gas. Our proposed model has been directly verified by the laboratory tests, and the gas relative permeability in different cases with varying Knudsen numbers has been computed. To our surprise, the calculated relative permeability curves for gas transport in narrow pores demonstrate as convex shape, which indicates that the influence of water on gas flow weakens as the increase of irreducible water saturation. This phenomenon become obvious especially in large Knudsen number condition. In fact, as the increase of Knudsen number, the gas slippage becomes significant and the relative impact of pre-adsorbed water reduces. For a typical tight gas reservoir with initial water saturation of 30%, the effective permeability for gas transport will reduce about 15%~30%, which depends on the Knudsen number for gas transport. Therefore, neglecting the effect of two-phase interaction might overestimate the gas deliverability.
Li, Jing (China University of Petroleum) | Li, Xiangfang (China University of Petroleum) | Wu, Keliu (University of Calgary) | Chen, Zhangxin John (University of Calgary) | Wang, Kun (University of Calgary) | Zhong, Minglu (The University of Hong Kong) | Bai, Zhijun (Powerchina Zhongnan Engineering Corporation Limited)
Characteristics of gas transport in nanopores are topics of great interest for evaluation of unconventional reservoirs. The apparent permeability model for single-phase gas flow has been extensively investigated. Few models, however, have been established for the gas transport in gas/liquid two-phase flow condition. Unfortunately, initial water always exists under reservoir condition. Although it is regarded as immobile state, the impact of which on gas flow capacity should not be simply neglected.
In this work, firstly, the state of sub-irreducible water saturation in unconventional reservoirs have been carefully investigated, and the thickness of thin film bound on inorganic pore surface (e.g. clay or quartz) has been quantified. Subsequently, by considering the impact of the water film on the effective hydraulic diameter, gas slip-flow model is established. Noting that the gas phase in moist conditions is mainly composed of both methane and vapor rather than single-component methane. Thus, the methane-vapor binary gas state equation has been introduced to describe the real gas effect under high pressure and temperature condition. Our proposed model has been directly verified by the laboratory tests, and the gas relative permeability in different cases with varying Knudsen numbers has been computed.
To our surprise, the calculated relative permeability curves for gas transport in narrow pores demonstrate as convex shape, which indicates that the influence of water on gas flow weakens as the increase of irreducible water saturation. This phenomenon become obvious especially in large Knudsen number condition. In fact, as the increase of Knudsen number, the gas slippage becomes significant and the relative impact of pre-adsorbed water reduces. For a typical tight gas reservoir with initial water saturation of 30%, the effective permeability for gas transport will reduce about 15%~30%, which depends on the Knudsen number for gas transport. Therefore, neglecting the effect of two-phase interaction might overestimate the gas deliverability.
Natural gas production of the United States from shale resources increased from 4 percent of total gas production in 2005 to 40 percent in 2012. These resources are different from conventional hydrocarbon resources due to the presence of extremely tight organic pores and low permeabilities. Presence of the nanopores may cause rarefaction effects, especially in laboratory conditions, which increases the effects of temperature and pressure on the apparent permeability of shale samples. In order to determine the permeability of these resources, laboratory measured apparent permeabilities, if conducted in low pressure and temperature, need to be extrapolated to reservoir conditions. In addition, gas flow in low pressures has important applications in predicting the gas production rates from unconventional reservoirs.
Analytical methods for estimating gas apparent permeability (AP) of shale have been already proposed, e.g. Navier-Stokes and Advective -Diffusive Models (ADM); however, they are valid for a limited range of Knudsen numbers (Kn < 0.5) and they have oversimplifying assumptions that overestimate the mass flux (or permeability) of nanopores. In addition, their results do not show the effect of temperature and gas molecular weight on AP.
The presented work aims to develop an analytical model for gas apparent permeability of nanopores which is valid for Knudsen number up to unity. Solutions to the Regularized 13 (R13)-moment equations (extension of Grad's 13-moments equations) provide a reliable tool to derive an analytical model for gas AP in nanotubes. The novelty of this work is that we provide an analytical model for gas AP which is valid for higher range of Knudsen numbers (by comparing with the kinetic data) in contrast to the previously developed analytical models. The new model is used to predict the impact of controlling parameters such as temperature, pressure, molecular weight, pore size, and Tangential Momentum Accommodation Coefficient (TMAC) on gas AP. It is shown that the gas molecular weight and temperature have significant effect on gas apparent permeability at low pressures. The effect of adsorption on AP of nanotubes is studied by employing the experimental Langmuir isotherms of different shale samples.
The bundle of tubes method is used to compare R13 AP model with the experimental data of a Marcellus shale core plug. The model's AP results for Nitrogen and Carbon Dioxide agree with the experimental measurements.