Study on physical aperture and fluid flow behavior after dislocation of a rough fracture

<p>In various reservoirs such as geothermal reservoirs or host rocks for nuclear waste, fractures and in particular fracture apertures play a crucial role in acting as conduits or even barriers, and therefore control fluid flow and solute transport in such reservoirs or host rocks. Often such reservoirs are simulated by discrete fracture network (DFN) models, whose performance however rely strongly on reliable input parameters such as fracture apertures under different conditions. Hence, in this study we examine various novel field and numerical methods, which are able to determine hydraulic, mechanical and even chemical apertures of natural fractures. First, we compare three different methods, (1) syringe air permeameter, (2) microscope camera and (3) laser scanner for determining hydraulic fracture apertures. Our results prove that the air permeameter allows direct and reliable measurements of hydraulic apertures in the laboratory and also in the field. Additionally, the novel air permeameter could be successfully validated by flow through experiments using various types of fractured core samples. In contrast, microscope camera and laser scanner only provide reliable mechanical apertures. In order to also simulate fracture closure under normal stresses, an innovative contact mechanical approach is introduced and validated using a granodiorite fracture. The simulations indicate the best performance for an elastic–plastic (EP) model, which fits almost perfectly the experimentally derived normal closure data. Finally, a phase-field model (PFM) for hydro­thermally induced quartz growth is used to understand the effect of sealing fractures on the flow behaviour. Our results demonstrate that flow behaviour and hydraulic properties of such chemically altered fractures, i.e. chemical fractures, significantly depend on the evolving crystal geometries. Consequently, a novel equation to estimate hydraulic apertures is derived, which includes a geometry factor α for dissimilar crystal geometries (α = 2.5 for needle quartz and α = 1.0 for compact quartz). Finally, the outcome of our studies clearly demonstrate that nowadays novel experimental and numerical methods exist to precisely determine various fracture apertures improving our understanding of coupled processes on the fluid flow behaviour in fractured media.</p><p>Acknowledgements to Florian Amann, Christoph Butscher, Frieder Enzmann, Christoph Naab, Jens Oliver Schwarz and Daniel Vogler</p>

Investigation on the unsteady-state two-phase fluid transport in the nano-pore system of natural tight porous media

The behavior of fluid flow has been studied during the different flow media over the past decades. In addition, the behavior of the flow of fluid through porous media has garnered much research interest. This paper sheds light on fissured rocks of oil reservoir media (as one of the porous media domain), and the effect of these fissured on fluid flow. In this article, the Finite Volume Method (FVM) has been used to visualize the behavior of single-phase fluid flow in an actual core according to the dualporosity dual permeability model. The study was conducted in two parts, the first was the image processing for one of the real oil reservoir fractured rock images, where the image was processed and simulated by ANSYSCFX software, and the results showed a complete visualizing of the fluid behavior during this domain. As for the other side, a simulation of a real reservoir rock belonging to the Al-Nour field in Iraq / Misan was made. The X-ray Computed Tomography (CT) scan has been used to convert the real fractured core to a dynamic domain. ANSYS-CFX program has been used and the results illustrated the pressure counter, the velocity counter, the velocity streamline, and the velocity vectors for the studied model in three dimensions. A comparison was made between the productivity index for fractured and non-fractured rock and the results explained that the presence of fracture can improve the productivity index to about 5.74%.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 164549, ’Optic Imaging of Two-Phase-Flow Behavior in Nanoscale Fractures,’ by Qihua Wu, Baojun Bai, SPE, and Yinfa Ma, Missouri University of Science and Technology; and Joeng Tai Ok, Keith Neeves, and Xiaolong Yin, SPE, Colorado School of Mines, prepared for the 2013 SPE Unconventional Resources Conference, The Woodlands, Texas, USA, 10-12 April. The paper has not been peer reviewed. Gas in tight sand and shale exists in underground reservoirs with microdarcy or even nanodarcy permeability ranges; these reservoirs are characterized by small pore throats and crack-like interconnections between pores. The physics of fluid flow in these rocks, with measured permeability in the nanodarcy range, is poorly understood. Knowing the fluid-flow behavior in the nanoscale channels is of major importance for both simulation studies and calculations of the relative permeability of gas in tight shale-gas systems. Introduction Shale-gas reservoirs have pore sizes in the range of 1 to 300 nm. Additionally, the matrix permeabilities of those unconventional gas reservoirs are in the microdarcy to nanodarcy range. When fluid (gas or water) flows in a shale pore, the molecule size is quite comparable to the flow diameter. When some gas molecules strike against the pore wall, they retain a certain velocity that causes them to “slip.” Under those conditions, Darcy’s equation may not be accurate or practical for describing the fluid-flow behavior because there may be other flow mechanisms at work such as slip flow and diffusive flow. Extensive studies have been conducted on single-phase flow in tight-sand and shale gas systems, and equations have been derived to measure the relative permeability of gas and to determine the single-phase gas-slippage effect. However, under real shale-gas-reservoir conditions, two phases (mostly water and gas) typically exist. It has been reported that in some ultralow-permeability shale-gas reservoirs, water saturation could be much greater than in conventional shale-gas plays. The effects of saturated water on gas permeability/relative permeability and gas slippage still have not been investigated sufficiently. For laboratory experiments, shale samples were used in most cases in order to represent the real pore structure and distribution in the reservoir. However, there are some limitations of using shale samples in laboratory experiments. For example, water saturation and saturation distribution are difficult to measure. Meanwhile, the laboratory-on-chip technique is becoming a suitable approach for investigating fluid flow in ultrasmall pores. Nano fluidics and microfluidics have been used in different subject areas for both fundamental research and application. Some micromodels are being used to study multiphase flow under both saturated and unsaturated conditions. Furthermore, the laboratory-on-chip technique provides a means by which to directly visualize fluid-flow behavior, such as the displacement of one fluid by another, because most micro-/nanofluidic chips are made of transparent materials. Micromodels have been used to simulate numerous porous-media-transport phenomena, including microorganism transport in unsaturated porous media. However, visualization studies of fluid flow in nanochannels are still lacking, especially for shale gas and tight gas.

Modeling of coupled thermal-hydraulic-mechanical-chemical processes for predicting the evolution in permeability and reactive transport behavior within single rock fractures

This paper aims to assess the influence of in situ stresses and geometry of the fracture surface on the behaviour of fluid flow through rock fractures. In this regard, fluid flow tests were performed on four mated, natural limestone fractures, under changing confining pressure ranging between 1.0 and 14 MPa. Based on the experimental observations, three types of relationship between pressure gradient and flow rate can be determined (linear, nonlinear induced by inertial effect and nonlinear induced by fracture dilation). Regression analyses of experimental data show that the nonlinearity induced by the inertial effect can be well quantified by the Forchheimer equation. The results of the experiments demonstrated that the confining pressure can change flow patterns from linear to nonlinear at higher flow rates, although by increasing the confining pressures the viscous and inertial coefficients in the Forchheimer equation show an increase of 10–40 and 2–10 times the initial magnitude, respectively. However, the rate of increase of the nonlinear coefficient b used in the Forchheimer equation steadily diminishes with the increase of confining pressure. The critical Reynolds number was successfully determined by taking a non-Darcy effect factor of 0.1, and the calculated critical Reynolds numbers show a decrease with further increase of the confining pressure and fracture roughness.

Miniaturization of traditional devices is in high demand formicro-electro-mechanical systems~MEMS!. Examples includebut are not limited to optics, communication and information sys-tems, fluidics, biotechnology, medicine, automotive, and aero-space. An area of interest in several engineering fields is the con-trol of fluid flow within microchannels and microtubes. Theapplications include, but are not limited to, fields such as vibrationcontrol of structures and systems using small devices, reactors formodification and separation of biological cells, energy systems asa mobile power supply, heat exchangers for micro and macro de-vices, and propulsion engines @1–3#.In recent years, there has been growing attention given to theliquid flow in microchannels in parallel with the development ofminiaturized devices and systems. The understanding of flowcharacteristics, such as velocity distribution and pressure loss isnecessary in design and process control of microfluidic devices.Peng, Peterson, and Wang @4# experimentally studied the flowcharacteristics of water flowing through rectangular microchan-nels having hydraulic diameters of 0.133 to 0.367 mm and heightto width ratios of 0.333 to 1. Their results indicated that the lami-nar flow transition occurred for the range of the Re number be-tween 200 and 700. They also claimed that friction behavior forboth laminar and turbulent flow depart from classical thermofluidcorrelations, and the friction factor is proportional to Re

Injection into unstimulated heavy oil reservoirs generally results in disturbance to the soil matrix. To correctly model the fluid distribution, the fluid flow behaviour must be coupled to the mechanical behaviour of the sands. A model has been developed representing the conditions present during isothermal leak-off from fracture face, accounting for the physics of this coupling. The model assumes that the minimum effective stress controls the soil behaviour and that the fluids are linearly compressible. The model satisfactorily represents fracture growth inferred from pressure observation wells and measured mean times for communication between cyclic steam stimulation wells. Several new features generated by the model can be correlated with field behaviour. Nonlinear compressibility of the oil sand at low effective confining stresses causes increases in porosity which explain observed injectivity with zero initial mobility. Shear failure occurs around a fracture primarily due :0 decreasing effective stresses as the local pore pressure increases: Dilatant failure behaviour increases porosity and permeability, producing plateaus of increased water saturation. The coupling of the fluid and solid mechanics in the new model represents a significant advance in the realism of modelling of fluid flow and fracturing in oil sands. Introduction Injection of hot water or steam in oil sands results in complex interactions of the soil mechanics of the uncemented matrix and fluid flow and heat transfer in porous media. In the past, the recovery mechanisms were studied mostly using multiphase flow models developed for consolidated porous media(1–3). Such models are not adequate for modelling oil sands with low initialobility and one has to resort to artificial means of providing injectivity. In 1980s the importance of the geotechnical aspects was recognized, but the applications were limited mostly to surface mining problems. In most in situ projects, the formation is fractured during the first, or several of the injection cycles. Early work on fracture modelling(4, 5) showed that the proper representation of the fracturing and soil mechanics will be the key to any realistic modelling effort in oil sands. To date, all models including the fracture have been severely compromised by poor treatment of fracture mechanics or assumptions of linear elasticity(6, 7). This work describes part of the results of an ongoing research effort for the development of a practical, but realistic model for thermal processes in oil sands. In this paper we will restrict the discussion to isothermal behaviour for the following reasons:It is necessary to understand isothermal behaviour before studying more complex thermal process.Fracture is established on the first cycle of steam injection during which the temperatures will be lowest. Due to heat transfer in the fracture, the injected fluid at the tip will have a temperature close to that of the reservoir. Even for the isothermal case, one has to deal with several facts observed in the field, which contradict classical reservoir and fracture mechanics:Observed fracture dimensions are relatively small and fracture widths are large(8).Injectivity is larger than what would correspond to in situ mobility of fluids(5).

It is essential to understand the hydraulic behavior of rock apertures as the fluid flow path in the rock mass. The geometric parameters of fracture such as roughness of walls and fracture aperture have a significant effect on its hydromechanical behavior. In this paper, the laboratory tests are performed on the samples and then, the laboratory conditions are numerically simulated. The three-dimensional (3D) scanning of the walls of natural rock fractures is used to prepare the geometric model, and the ICEM CFD software is employed to prepare the geometry of fractures. Also, using the Ansys Fluent software and considering the Navier-Stokes equations in the model, the fluid flow in the rock fractures is simulated. Due to the fact that the two joint surfaces are in contact with each other, the model geometry is constructed in the case when the joints are mated and the contact is established in a certain percentage. In this way, the geometries are prepared for 15, 30, 45, 60, 75, and 90% contact between the upper and lower surfaces. The numerical modeling is also validated by the analytical Darcy formula, which indicates the accuracy of the modeling technique. The modeling results show that the macroscopic Forchheimer relation well describes the nonlinear fluid flow in the rock fracture. The values of linear and nonlinear coefficients of Forchheimer equation are estimated for each of the geometric models. The results show that the Forchheimer coefficients are directly related to the joint contact surface in an exponential manner, and the hydraulic aperture increases proportional to the reduced joint contact surface.

Influence of surface roughness on nonlinear flow behaviors in 3D self-affine rough fractures: Lattice Boltzmann simulations

Photogrammetry, reconstructing three-dimensional (3D) models from overlapping two-dimensional (2D) photos, finds application in rock mechanics and rock engineering to extract geometrical details of reconstructed objects, for example rock fractures. Fracture properties are important for determining the mechanical stability, permeability, strength, and shear behavior of the rock mass. Photogrammetry can be used to reconstruct detailed 3D models of two separated rock fracture surfaces to characterize fracture roughness and physical aperture, which controls the fluid flow, hydromechanical and shear behavior of the rock mass. This research aimed to determine the optimal number of scale bars required to produce high-precision 3D models of a fracture surface. A workflow has been developed to define the physical aperture of a fracture using photogrammetry. Three blocks of Kuru granite (25 cm × 25 cm × 10 cm) with an artificially induced fracture, were investigated. For scaling 3D models, 321 markers were used as ground control points (GCPs) with predefined distances on each block. When the samples were well-matched in their original positions, the entire block was photographed. Coordinate data of the GCPs were extracted from the 3D model of the blocks. Each half was surveyed separately and georeferenced by GCPs and merged into the same coordinate system. Two fracture surfaces were extracted from the 3D models and the vertical distance between the two surfaces was digitally calculated as physical aperture. Accuracy assessment of the photogrammetric reconstruction showed a 20–30 μm digital control distance accuracy when compared to known distances defined between markers. To attain this accuracy, the study found that at least 200 scale bars were required. Furthermore, photogrammetry was employed to measure changes in aperture under normal stresses. The results obtained from this approach were found to be in good agreement with those obtained using linear variable displacement transducers (LVDTs), with differences ranging from 1 μm to 8 μm.

New approach for improved history matching while incorporating wettability variations in a sandstone reservoir—Field implementation

Depressurization of hydrate‐bearing sediments (HBS) can cause the movement of fine particles, and in turn, such fines migration affects fluid flow and mechanical behavior of sediments, ultimately affecting long‐term hydrocarbon production and wellbore stability. This study investigated how and to what extent depressurization of HBS causes fines migration using X‐ray computed tomography (CT) imaging. Methane hydrate was synthesized in sediments with 10% fines content (FC), composed of sands with silt and/or clay, and the hydrate‐bearing samples were stepwisely depressurized while acquiring CT images. The CT images were analyzed to quantify the spatial changes in FC in the host sediment and thus to capture the fines migration during depressurization. It was found that the FC changes began occurring from the hydrate dissociation regions. This confirms that the multiphase flow caused by depressurization accompanies fines migration. Depressurization of HBS with a hydrate saturation of ~20–40% caused FC reduction from ~10% to ~6–9%, and the extent of fines migration differed with the particle sizes of the host sands and the types of fines. It was found that fines migration was more pronounced with coarse sands and with silty fines. Such observed level of FC reduction is estimated to increase sediment permeability by several factors based on the Kozeny‐type permeability model. Our results support the notion that the extent of fines migration and its effect on fluid flow behavior need to be assessed in consideration of physical properties of host sediment and fine particles to identify optimum depressurization strategies.

Understanding nonlinear fluid flow in fractured rocks is critical for various geoengineering and geosciences. This study investigates the evolution of seepage behavior under varying fracture surface roughness, confining pressures, and shear displacements. A total of four sandstone fracture specimens were prepared using controlled splitting techniques, with surface morphology quantified by Joint Roughness Coefficient (JRC) values ranging from 2.8 to 17.7. Triaxial seepage tests were conducted under four confining pressures (3–9 MPa) and four shear displacements (0–1.5 mm). Experimental results reveal that permeability remains stable under low hydraulic gradients but transitions to nonlinear regimes as the flow rate increases, accompanied by significant energy loss and deviation from the cubic law. The onset of nonlinearity occurs earlier with higher roughness, stress, and displacement. A critical hydraulic gradient Jc was introduced to define the threshold at which inertial effects dominate. Forchheimer’s equation was employed to model nonlinear flow, and empirical regression models were developed to predict coefficients A, B, and Jc using hydraulic aperture and JRC as input variables. These models demonstrated high accuracy (R2 > 0.92). This work provides theoretical insights and predictive approaches for assessing nonlinear fluid transport in rock fracture. Future research will address mechanical–hydraulic coupling and incorporate additional factors such as scale effects and flow anisotropy.

Modeling of fluid flow in rock fractures is a key issue in answering numerous geoengineering problems in the fields of geophysics, reservoir engineering, rock mechanics, to geothermal processes. Although fluid flow in single fractures has been extensively studied in the last 7 decades, fractures commonly seen in fractured reservoir systems intersect each other forming complex geometric structures. Such fracture networks likely affect fluid flow behavior and solute transport. To investigate the impact of geometric characteristics of connected rough-walled fractures with an X junction shape on linear and nonlinear fluid flow behaviors, a sensitivity analysis was carried out by conducting a series of numerical fluid flow simulations on X shape fractures, generated by scanning real rock fractures with distinct roughness (low, medium, and high), intersecting angles, and apertures. The fluid flow through these fractures at different flow rates was simulated by solving Naiver-Stokes equations. The results show that tortures paths and the formation of eddies are more accentuated on the rough fracture than the smoother ones, and the tortuosity of the streamlines is related to the roughness and the geometric characteristics of the intersection. Simulation results of the different models were compared, which show that the intersection significantly impacts the relationship between the hydraulic gradient and the flow. Therefore, the pressure gradient increases with the decrease of the intersection angle especially for low aperture and rough cases. INTRODUCTION Understanding fluid flow through a fractured rock mass has great importance to numerous underground industrial activities, such as geothermal extraction (Zhao, 2016), CO2 storage (Catherine Noiriel et al., 2013), oil and gas exploration (Bo Li et al., 2016), underground oil storage (Qiao et al., 2017; Wang et al., 2015), and hydraulic fracturing (Blanton TL,1982). It is important to measure the impact of roughness to improve the performance of large-scale models since most existing large-scale models still rely heavily on simplified smooth parallel-plate models and related models for natural rock fractures with rough walls (Zimmerman et al., 1992; Zimmerman and Bodvarsson, 1996; Ge 1997; Bodin et al., 2007; Zhao et al., 2013; Wang et al., 2015).