Masoud Alfi

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.

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.