Bicheng Yan

Beyond dual-porosity modeling for the simulation of complex flow mechanisms in shale reservoirs

The state of the art of modeling fluid flow in shale reservoirs is dominated by dual-porosity models which divide the reservoirs into matrix blocks that significantly contribute to fluid storage and fracture networks which principally control flow capacity. However, recent extensive microscopic studies reveal that there exist massive micro- and nano-pore systems in shale matrices. Because of this, the actual flow mechanisms in shale reservoirs are considerably more complex than can be simulated by the conventional dual-porosity models and Darcy’s law. Therefore, a model capturing multiple pore scales and flow can provide a better understanding of the complex flow mechanisms occurring in these reservoirs. This paper presents a micro-scale multiple-porosity model for fluid flow in shale reservoirs by capturing the dynamics occurring in three porosity systems: inorganic matter, organic matter (mainly kerogen), and natural fractures. Inorganic and organic portions of shale matrix are treated as sub-blocks with different attributes, such as wettability and pore structures. In kerogen, gas desorption and diffusion are the dominant physics. Since the flow regimes are sensitive to pore size, the effects of nano-pores and micro-pores in kerogen are incorporated into the simulator. The multiple-porosity model is built upon a unique tool for simulating general multiple-porosity systems in which several porosity systems may be tied to each other through arbitrary connectivities. This new model allows us to better understand complex flow mechanisms and eventually is extended into the reservoir scale through upscaling techniques. Sensitivity studies on the contributions of the different flow mechanisms and kerogen properties give some insight as to their importance. Results also include a comparison of the conventional dual-porosity treatment and show that significant differences in fluid distributions and dynamics are obtained with the improved multiple-porosity simulation.

Compositional Modeling of Tight Oil Using Dynamic Nanopore Properties

A typical tight oil reservoir such as the Bakken has matrix pore sizes ranging from 10 nm to 50 nm. At such small scales the confined hydrocarbon phase behavior deviates from bulk measurements due to the effect of capillary pressure. In addition, compaction of pore space can bring about order of magnitude changes for tight oil formation properties during pressure depletion further exacerbating these deviations. Without considering these facts a conventional reservoir simulator will likely not be able to explain the inconsistent produced GOR observed in the field compared to simulated results. The effect of these inaccuracies on ultimate recovery estimation can be devastating to the underlying economics. This paper presents a compositional tight oil simulator that rigorously models pressure dependent nanopore-impacted rock and fluid properties, such as suppression of bubble point pressure, decrease of liquid density, and reduction of oil viscosity as well as their interactions with pore space compaction. The cubic Peng-Robinson equation of state is used for phase behavior calculations. Capillary pressure is evaluated by standard Leverett J-function for porous media. Modifications to the stability test and two-phase split flash calculation algorithms are provided to consider the capillarity effect on vaporliquid equilibrium. The simulator can capture the pressure-dependent impact of the nanopore structure on rock and fluid properties. As a result, the problem of inconsistent GOR is resolved and the history matching process is greatly facilitated. It is shown that inclusion of these enhanced physics in the simulation will lead to significant improvements in field operation decisionmaking and greatly enhance the reliability of recovery predictions. Introduction The recent advances in massive hydraulic fracturing techniques have enabled the oil industry to economically extract hydrocarbon from ultra-tight, unconventional resources, such as shale gas, liquid rich shale and tight oil. The success in North America has stimulated the development of unconventional plays worldwide. For example, a marine shale play in southern China has showed large potential and attracted great attention (Wei et al. 2012; 2013a, b). However, despite the great success and potential, the understanding of fluid flow mechanism in shale and properties in confined pore space is still poor. The flow mechanism in the shale matrix is complicated by organic and inorganic portions of the matrix with distinct wettabilities. Yan et al. (2013 a, b, c, d) proposed a micro-model to model single-phase gas and two-phase gas-water flow in shale matrix blocks by considering different flow mechanisms in organic and inorganic nanopores. Yan’s work also upscaled the single-phase gas flow to well-scale modeling via the apparent permeability approach. On the other hand, the fluid properties in the confined nanopore space deviate from the corresponding bulk measurements in which zero vapor-liquid interface curvature is assumed. This assumption is generally held when the vapor-liquid equilibrium takes place in PVT cells. But, when the fluid is confined in pore spaces of nano-size, the significant interfacial curvature may cause a large capillary pressure difference between liquid and vapor phases. The effect of capillary pressure on vapor-liquid equilibrium is not new to the oil industry. A number of researchers have conducted both experimental and theoretical investigations with general conclusions that capillarity effect on vapor-liquid equilibrium is negligible for conventional reservoirs (Leverett 1941; Sigmund et al. 1973, 1982; Shapiro and Stenby 1997; Shaprio et al. 2000). Perhaps due to this reason, essentially all the current commercial simulators assume no pressure difference between vapor and liquid phases during flash calculations. However, ignoring capillarity in vapor-liquid equilibrium might not be a valid assumption for unconventional reservoirs. A typical tight oil reservoir such as the Bakken has matrix pore size ranging from 10 nm to 50 nm. At such small scales, the confined hydrocarbon phase behavior is believed to deviate from bulk measurements due to the extra capillarity effect. Rock wettability is another factor to consider when dealing with capillary pressures. Wang et al. (2012) performed a wettability

A New Approach for the Simulation of Fluid Flow In Unconventional Reservoirs Through Multiple Permeability Modeling

Shale reservoirs are characterized by ultra-low permeability, multiple porosity types, and complex fluid storage and flow mechanisms. Consequentially the feasibility of performing simulations using conventional Dual Porosity Models based on Darcy flow has been frequently challenged. Additionally, tracking of water in shale continues to be controversial and mysterious. In organic-rich shale, kerogen is generally dispersed in the inorganic matter. Kerogen is different from any other shale constituents because it tends to be hydrocarbon-wet, abundant in nanopores, fairly porous and capable of adsorbing gas. However, the inorganic matter is usually water wet with low porosity such that capillary pressure becomes the dominant driving mechanism for water flow, especially during hydraulic fracturing operations. This work presents a technique of subdividing shale matrices and capturing different mechanisms including Darcy flow, gas diffusion and desorption, and capillary pressure. The extension of this technique forms a solid and comprehensive basis for a specially-designed simulator for fractured shale reservoirs at the micro-scale. Through the use of this unique simulator, this paper presents a micro-scale two-phase flow model which covers three continua (organic matter, inorganic matter and natural fractures) and considers the complex dynamics in shale. In the model, TOC is an indispensable parameter to characterize the kerogen in the shale. A unique tool for general multiple porosity systems is used so that several porosity systems can be tied to each other through arbitrary connections. The new model allows us to better understand the complex flow mechanisms and to observe the water transfer behavior between shale matrices and fractures under a microscopic view. Sensitivity analysis studies on the contributions of different flow mechanisms, kerogen properties, water saturation and capillary pressure are also presented. Introduction In recent years, unconventional resources have played a significant part to balance between the increasing energy demand and the shortage of production from the conventional reservoirs in the United States (Wei et al. 2013). Hydrocarbon from organic rich shale is one of the most significant unconventional resources. The successful development of shale reservoirs is greatly attributed to horizontal well drilling and hydraulic fracturing operations. In industry, effective hydraulic fracturing for shale wells is performed mainly through injecting slickwater under high pressure. However, generally the recovery of fracturing fluid is quite low. King (2012) suggested that the water might be trapped in the small pores and the micro-fractures of shale. Besides, evidence shows that there is a high concentration of chloride salts in the flowback fluid, while it cannot be explained either from the composition of fracturing fluid (mostly fresh water) or from the constituents of shale and the salinity of formation brine (King 2012). Wang and Reed (2009) propose that there exist four pore systems in the organic-rich shale: inorganic matter, organic matter (kerogen), natural fractures and hydraulic fractures. It is also suggested that the organic matter is oil wet and that single oil or gas phase flow without residual water is dominated in kerogen fragments. However, the inorganic matrix is mostly considered as water-wet (Kalakkadu et al. 2013). Through the approach of Molecular Dynamics Simulation and with the initial condition of water and NaCl, Hu et al. (2013) suggested that water could be filled in the larger pores in the kerogen through capillary condensation but no water enters the smaller 0.9 nm kerogen pores. Water exists in the inorganic MgO pores in the liquid phase; meanwhile, there is a much higher ionic concentration in the inorganic matter than that in the kerogen. In shale gas reservoirs, the source of shale gas can be thermogenic, biogenic or combined source (Darishchev et al. 2013). Natural gas is usually considered to exist in three forms: compressed gas in pores and fissures, adsorbed gas in the organic and inorganic matter, and dissolved gas in the kerogen (Javadpour 2009; Zhang et al. 2012). Usually it might be reasonable

How to Improve our Understanding of Gas and Oil Production Mechanisms in Liquid-rich Shale

Three phase oil, gas, and water flow in liquid-rich shale plays is investigated in this paper, using a state-of-the-art technique of dividing shale matrix into different sub-media. Shale reservoirs always present numerous challenges to modeling and understanding, from unintuitive, heterogeneous, and difficult to characterize rock properties, to limited understanding of the governing flow equations, lack of fundamental knowledge on related desorption mechanisms, and nearly impermeable formations with pores on the order of magnitude as the mean free path of gas molecules. This work proposes a partitioning scheme to divide porous media in shale into three different sub-media (porosity systems) with distinctive characteristics: inorganic matter and kerogen (in the shale matrix), along with fracture network (natural or hydraulic). The current model gives us the capability of better analyzing the complex nature of mass transfer in shale. Relative permeabilities in our model are accounted for by employing the functions specifically presented for shale reservoirs. Our model can also handle various flow and storage mechanisms corresponding with shales such as molecule/wall interactions and slippage of the gas phase, multicomponent desorption, and capillarities. Simulation results show that hydrocarbon production from shale reservoirs exhibits complicated dynamics that are controlled by a number of different factors. Because of very high capillary pressure in shale, water is observed to imbibe into the water-wet inorganic matter during the late production period. On the contrary, mass flow in the oil-wet kerogen is mostly limited to two-phase oil and gas flow. Although kerogen is considered to be a rich source of hydrocarbon, relatively high capillary pressure and very low rock permeability hinder oil production in organic-rich shale. We might be able to address such problems by employing an appropriate production enhancement technique compatible with the ultra-tight nature of such reservoirs.

Beyond Dual-Porosity Modeling for the Simulation of Complex Flow Mechanisms in Shale Reservoirs

The state of the art of modeling fluid flow in shale reservoirs is dominated by dual porosity models which divide the reservoirs into matrix blocks that significantly contribute to fluid storage and fracture networks which principally control flow capacity. However, recent extensive microscopic studies reveal that there exist massive microand nanopore systems in shale matrices. Because of this, the actual flow mechanisms in shale reservoirs are considerably more complex than can be simulated by the conventional dual porosity models and Darcy’s Law. Therefore, a model capturing multiple pore scales and flow can provide a better understanding of complex flow mechanisms occurring in these reservoirs. Through the use of a unique simulator this paper presents a micro-scale multiple-porosity model for fluid flow in shale reservoirs by capturing the dynamics occurring in three separate porosity systems: organic matter (mainly kerogen), inorganic matter, natural fractures. Inorganic and organic portions of shale matrix are treated as sub-blocks with different attributes, such as wettability and pore structures. In the organic matter or kerogen, gas desorption and diffusion are the dominant physics. Since the flow regimes are sensitive to pore size, the effects of nanopores and vugs in kerogen are incorporated into the simulator. The separate inorganic sub-blocks mainly contribute to the ability to better model dynamic water behavior. The multiple porosity model is built upon a unique tool for simulating general multiple porosity systems in which several porosity systems may be tied to each other through arbitrary transfer functions and connectivities. This new model allows us to better understand complex flow mechanisms and in turn is extended into the reservoir scale considering hydraulic fractures through upscaling techniques. Sensitivity studies on the contributions of the different flow mechanisms and kerogen properties give some insight as to their importance. Results also include a comparison of the conventional dual porosity treatment and show that significant differences in fluid distributions and dynamics are obtained with the improved multiple porosity simulation. Finally a case for reservoir-scale model covering organic matter, inorganic matter, natural fractures and hydraulic fractures is presented and will allow operators to better predict ultimate recovery from shale reservoirs. Introduction The development of unconventional resource plays in North America has achieved great success towards satisfy the growing energy demand. The organic shale formations which provide the basis of unconventional oil and gas production continue as an enigma as far as understanding production characteristics are concerned. Because of this many investigators have been inspired to establish suitable models to characterize fluid flow in shale encountering great challenges along the way. Shale is referred to as extraordinarily fine-grained sediments commonly showing fissility (Javadpour, 2009). Loucks et al. (2012) systematically classified nanometer to micrometer sized pores in the shale matrix into interparticle pores and intraparticle pores associated with mineral particles and organic-matter pores within kerogen. The organic matter has different physical properties from common rock constituents and could significantly affect gas storage and flow in shale. Curtis et al. (2010) found that mostly kerogen is scattered in inorganic minerals, and pores within it are basically round in cross-section interestingly with numerous small pores residing on the interior walls of larger pores. Due to forming during the process of hydrocarbon generation, the pore networks in the organic matter in shale are mainly considered to be oilor gas-wet (Wang et al., 2009; Odusina et al., 2011). Experiments on Barnett Shale demonstrated that the both adsorbed gas and free gas stored in the shale matrix are linearly increased with TOC content (Jarvie, 2004), and Javadpour (2009) also theoretically proposed that beside free gas storage in shale, gas could also be adsorbed on the surface of kerogen and dissolved within it. Hill et al. (2000)

Modeling of Magnetic Nanoparticle Transport in Shale Reservoirs

Currently, the application of nanoparticles has attracted much attention due to the potential of nanotechnology to lead to revolutionary changes in the petroleum industry. The literature contains numerous references to the possible use of this technology for enhanced oil recovery, nano-scale sensors and subsurface mapping. Little work has been conducted to establish numerical models to investigate nanoparticle transport in reservoirs, and even less for shale reservoirs. Unlike conventional reservoirs, shale formations usually contain four pore systems: inorganic matter, organic matter dominated by hydrocarbon wettability, natural fractures and hydraulic fractures. Concurrently, hydraulic fractures and the associated stimulated reservoir volume (SRV) from induced fractures play a critical role in significantly increasing well productivity. In this paper, a mathematical model for simulating nanoparticle transport in shale reservoirs was developed. The simulator includes contributions from Darcy flow, Brownian diffusion, gas diffusion and desorption, slippage flow, and capillary effects based on the extremely low permeability and microto nano-scale of the pores. Moreover, these diverse mechanisms are separately applied to different portions of the reservoir due to the variation in media properties. Applications of the model include numerical examples from two-dimensional micro models to macro models, both with organic matter randomly distributed within the inorganic matrix. The effects of varying water saturation, grid pressure, and mass concentration of nanoparticles are shown graphically in these numerical examples. The main conclusion from these models is that, as expected, nanoparticles can only easily flow along with the aqueous phase into the fractures, but their transport into the shale matrix is quite limited, with little transport shown into the organic matter. In addition, based on the measured properties of synthesized magnetic carbon-coated iron-oxide nanoparticles, the distribution of the volumetric magnetic susceptibility and the magnetization of reservoir including SRV are simulated and displayed in the numerical cases with and without magnetic nanoparticles. The results demonstrate that magnetic nanoparticles can effectively enlarge the magnetic susceptibility and the magnetization of reservoir thus producing enhanced signals from well logging devices such as Nuclear magnetic resonance (NMR) and leading to improved reservoir and fracture characterization. This simulator can provide the benefits of both numerically simulating the transport and distribution of nanoparticles in hydraulically fractured shale formations and supplying helpful guidelines for nanoparticles injection plans to enhance well logging signals. Furthermore, this model can also allow us to mimic the tracer transport flow in unconventional reservoirs.