Mechanical-Chemical-Mineralogical Controls on Permeability Evolution of Shale Fractures

We report experimental observations of permeation of CO2-rich aqueous fluids of varied acidic potential (pH) on three different shales to investigate mechanical, chemical, and mineralogical effects on fracture permeability evolution. Surface profilometry and SEM-EDS (scanning electron microscopy with energy-dispersive X-ray spectroscopy) methods are employed to quantify the evolution in both roughness on and chemical constituents within the fracture surface. Results indicate that, after 12 hours of fluid flow, fracture effective hydraulic apertures evolve distinctly under different combinations of shale mineralogy, effective stress, and fluid acidity. The evolution of roughness and transformation of chemical elements on the fracture surface are in accordance with the evolution of permeability. The experimental observations imply that (1) CO2-rich aqueous fluids have significant impact on the evolution of fracture permeability and may influence (and increase) shale gas production; (2) shale mineralogy, especially calcite mineral, decides the chemical reaction and permeability increasing when CO2-rich aqueous fluids flow through fractures by free-face dissolution effect; (3) clay mineral swelling reduces fracture aperture and additively calcite pressure solution removes the bridging asperities, which are the main reasons for fracture permeability decrease; (4) competition roles among clay mineral swelling, mineral pressure solution, and free-face dissolution determine how fracture permeability changes. Furthermore, a multiple parameter model is built to analyze effective hydraulic aperture evolution in considering above three mechanisms, which provide a reference to forecast fracture permeability evolution in shale formations.

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Evolution of Fracture Aperture in Quartz Sandstone under Hydrothermal Conditions: Mechanical and Chemical Effects

Minerals ◽

10.3390/min10080657 ◽

2020 ◽

Vol 10 (8) ◽

pp. 657

Author(s):

Chaojie Cheng ◽

Harald Milsch

Keyword(s):

Fluid Flow ◽

Hydraulic Fracture ◽

Chemical Equilibrium ◽

Pore Fluid ◽

Pressure Solution ◽

Fracture Aperture ◽

Hydraulic Aperture ◽

Mechanical Aperture ◽

Stagnant Flow

Fractures efficiently affect fluid flow in geological formations, and thereby determine mass and energy transport in reservoirs, which are not least exploited for economic resources. In this context, their response to mechanical and thermal changes, as well as fluid–rock interactions, is of paramount importance. In this study, a two-stage flow-through experiment was conducted on a pure quartz sandstone core of low matrix permeability, containing one single macroscopic tensile fracture. In the first short-term stage, the effects of mechanical and hydraulic aperture on pressure and temperature cycles were investigated. The purpose of the subsequent intermittent-flow long-term (140 days) stage was to constrain the evolution of the geometrical and hydraulic fracture properties resulting from pressure solution. Deionized water was used as the pore fluid, and permeability, as well as the effluent Si concentrations, were systematically measured. Overall, hydraulic aperture was shown to be significantly less affected by pressure, temperature and time, in comparison to mechanical aperture. During the long-term part of the experiment at 140 °C, the effluent Si concentrations likely reached a chemical equilibrium state within less than 8 days of stagnant flow, and exceeded the corresponding hydrostatic quartz solubility at this temperature. This implies that the pressure solution was active at the contacting fracture asperities, both at 140 °C and after cooling to 33 °C. The higher temperature yielded a higher dissolution rate and, consequently, a faster attainment of chemical equilibrium within the contact fluid. X-ray µCT observations evidenced a noticeable increase in fracture contact area ratio, which, in combination with theoretical considerations, implies a significant decrease in mechanical aperture. In contrast, the sample permeability, and thus the hydraulic fracture aperture, virtually did not vary. In conclusion, pressure solution-induced fracture aperture changes are affected by the degree of time-dependent variations in pore fluid composition. In contrast to the present case of a quasi-closed system with mostly stagnant flow, in an open system with continuous once-through fluid flow, the activity of the pressure solution may be amplified due to the persistent fluid-chemical nonequilibrium state, thus possibly enhancing aperture and fracture permeability changes.

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Experimental Reproducibility and Natural Variability of Hydraulic Transport Properties of Fractured Sandstone Samples

Geosciences ◽

10.3390/geosciences10110458 ◽

2020 ◽

Vol 10 (11) ◽

pp. 458

Author(s):

Sascha Frank ◽

Thomas Heinze ◽

Mona Ribbers ◽

Stefan Wohnlich

Keyword(s):

Fracture Surface ◽

Surface Morphology ◽

Transport Properties ◽

Natural Variability ◽

Transport Processes ◽

Fracture Aperture ◽

Hydraulic Transport ◽

Fracture Surface Morphology ◽

Transport Parameters ◽

Hydraulic Aperture

Flow and transport processes in fractured systems are not yet fully understood, and it is challenging to determine the respective parameters experimentally. Studies on 10 samples of 2 different sandstones were used to evaluate the reproducibility of tracer tests and the calculation of hydraulic transport properties under identical boundary conditions. The transport parameters were determined using the advection–dispersion equation (ADE) and the continuous time random walk (CTRW) method. In addition, the fracture surface morphology and the effective fracture aperture width was quantified. The hydraulic parameters and their variations were studied for samples within one rock type and between both rock types to quantify the natural variability of transport parameters as well as their experimental reproducibility. Transport processes dominated by the influence of fracture surface morphology experienced a larger spread in the determined transport parameters between repeated measurements. Grain size, effective hydraulic aperture and dispersivity were identified as the most important parameters to evaluate this effect, as with increasing fracture aperture the effect of surface roughness vanishes and the experimental reproducibility increases. Increasing roughness is often associated with the larger effective hydraulic aperture canceling out the expected increased influence of the fracture surface morphology.

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Flow-induced alterations of ultrasonic signatures and fracture aperture under constant state of stress in a single-fractured rock

Geophysics ◽

10.1190/geo2018-0574.1 ◽

2019 ◽

Vol 84 (4) ◽

pp. WA115-WA125 ◽

Cited By ~ 3

Author(s):

Arash Kamali-Asl ◽

Bijay KC ◽

Ehsan Ghazanfari ◽

Ahmadreza Hedayat

Keyword(s):

Fracture Surface ◽

Wave Attenuation ◽

Ultrasonic Waves ◽

P Wave ◽

Fracture Aperture ◽

Frequency Content ◽

Time Frequency ◽

State Of Stress ◽

Hydraulic Aperture ◽

Constant State

Fluid-fracture surface interaction, caused by different mechanisms, is one of the underlying reasons for permeability reduction over long period of time in different georesources, such as deep geothermal systems and shale gas/oil reservoirs. The sensitivity of the ultrasonic signatures (e.g., frequency content, velocity, amplitude, and attenuation) to the changes in fracture aperture caused by fluid-fracture surface interactions can be considered as a probe for flow-induced fracture aperture evolution. Flow-through tests on an artificially fractured phyllite specimen from a geothermal reservoir along with the concurrent measurements of ultrasonic signatures of P- and cross-polarized S-waves demonstrated the sensitivity of ultrasonic signatures to the evolution of fracture aperture/permeability under a constant state of stress (i.e., constant pore and confining pressures). In particular, the closure of the fracture and the decrease of permeability led to an increase of the P-wave velocity, a decrease of the P-wave attenuation, and an increase of the S-wave amplitude. In addition, time evolution of the time-frequency maps of the transmitted ultrasonic waves revealed that partitioning of the frequency content slightly changes because the fracture aperture/permeability is altered. Specifically, alterations in hydraulic aperture are reflected in the changes of time-frequency partitioning, whereas under constant hydraulic aperture, the time-frequency partitioning is unaltered.

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Long-term evolution of fracture permeability in slate as potential target reservoirs for Enhanced Geothermal Systems (EGS)

10.5194/egusphere-egu21-12187 ◽

2021 ◽

Author(s):

Chaojie Cheng ◽

Johannes Herrmann ◽

Erik Rybacki ◽

Harald Milsch

Keyword(s):

Room Temperature ◽

Time Dependent ◽

Emission Spectrometry ◽

Intermittent Flow ◽

Fracture Aperture ◽

Enhanced Geothermal Systems ◽

Permeability Reduction ◽

Permeability Evolution ◽

Fracture Permeability

<p>The long-term sustainability of fractures in Variscan metamorphic rocks will determine whether it is reasonable to utilize such formations as potential unconventional EGS reservoirs. During long lasting fluid flow within fractures, dissolution, precipitation, and chemical reactions between the fluid and the rock matrix may alter the flow pathway structure and flow properties. Within the framework of the European Union's Horizon 2020 initiative "MEET (Multi-Sites EGS Demonstration)", we performed long-term fracture permeability experiments on saw-cut slate samples from the Hahnenklee drill site, Harz Mountains, Germany, under constant pressure and temperature conditions. Two experiments were performed using deionized water as pore fluid with intermittent flow for more than one month at 10 MPa confining pressure and 1 MPa pore pressure. Three sequential investigations were performed, including (1) an initial continuous flow tests at room temperature, (2) temperature cycles between room temperature and up to 70 &#176;C or 90 &#176;C, and (3) measurement of the time-dependent permeability evolution at 70 &#176;C or 90 &#176;C. During stage (3), the effluents were sampled in time intervals of 6 days and analyzed using inductively coupled plasma optical emission spectrometry (ICP-OES). The results show that (1) sample permeability first continuously decreases, but progressively converges within about three days, (2) increasing temperature leads to an additional permeability decline that is irreversible, and (3) the time-dependent permeability reduction is much more pronounced at 90 &#176;C in comparison to that at 70 &#176;C. The effluents are enriched with Na, Fe, K, Ca, Si, where the Na concentration is always an order of magnitude higher than the others. Except for Si, concentrations are progressively decreasing with time. During the entire experimental period, sample permeability was reduced by approximately 90% at 90 &#176;C and 60% at 70 &#176;C compared to their initial values. In contrast, both samples showed a negligible permeability decline with time at room temperature after cooling. Our results demonstrate that thermally-enhanced fluid-rock interactions lead to a permanent and at least partial closure of fracture aperture, which is unfavorable for geothermal exploitation. However, the degree of permeability reduction may strongly depend on initial fracture roughness, which remains to be investigated.</p>

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Evolution of Coal Permeability during Gas Injection—From Initial to Ultimate Equilibrium

Energies ◽

10.3390/en11102800 ◽

2018 ◽

Vol 11 (10) ◽

pp. 2800 ◽

Cited By ~ 5

Author(s):

Xingxing Liu ◽

Jinchang Sheng ◽

Jishan Liu ◽

Yunjin Hu

Keyword(s):

Effective Stress ◽

Local Equilibrium ◽

Fracture Aperture ◽

Permeability Evolution ◽

Full Spectrum ◽

Coal Permeability ◽

Fracture Pressure ◽

Permeability Changes ◽

Apparent Equilibrium ◽

Non Equilibrium

The evolution of coal permeability is vitally important for the effective extraction of coal seam gas. A broad variety of permeability models have been developed under the assumption of local equilibrium, i.e., that the fracture pressure is in equilibrium with the matrix pressure. These models have so far failed to explain observations of coal permeability evolution that are available. This study explores the evolution of coal permeability as a non-equilibrium process. A displacement-based model is developed to define the evolution of permeability as a function of fracture aperture. Permeability evolution is tracked for the full spectrum of response from an initial apparent-equilibrium to an ultimate and final equilibrium. This approach is applied to explain why coal permeability changes even under a constant global effective stress, as reported in the literature. Model results clearly demonstrate that coal permeability changes even if conditions of constant effective stress are maintained for the fracture system during the non-equilibrium period, and that the duration of the transient period, from initial apparent-equilibrium to final equilibrium is primarily determined by both the fracture pressure and gas transport in the coal matrix. Based on these findings, it is concluded that the current assumption of local equilibrium in measurements of coal permeability may not be valid.

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The influence of fault reactivation on injection-induced dynamic triggering of permeability evolution

Geophysical Journal International ◽

10.1093/gji/ggaa382 ◽

2020 ◽

Vol 223 (3) ◽

pp. 1481-1496

Author(s):

Elif Cihan Yildirim ◽

Kyungjae Im ◽

Derek Elsworth

Keyword(s):

Pore Pressure ◽

Fluid Pressure ◽

Fault Reactivation ◽

Permeability Evolution ◽

Fracture Permeability ◽

Permeability Enhancement ◽

Pressure Pulses ◽

Fracture Sealing ◽

Permeability Increase ◽

Pressure Driven

SUMMARY Mechanisms controlling fracture permeability enhancement during injection-induced and natural dynamic stressing remain unresolved. We explore pressure-driven permeability (k) evolution by step-increasing fluid pressure (p) on near-critically stressed laboratory fractures in shale and schist as representative of faults in sedimentary reservoirs/seals and basement rocks. Fluid is pulsed through the fracture with successively incremented pressure to first examine sub-reactivation permeability response that then progresses through fracture reactivation. Transient pore pressure pulses result in a permeability increase that persists even after the return of spiked pore pressure to the null background level. We show that fracture sealing is systematically reversible with the perturbing pressure pulses and pressure-driven permeability enhancement is eminently reproducible even absent shear slip and in the very short term (order of minutes). These characteristics of the observed fracture sealing following a pressure perturbation appear similar to those of the response by rate-and-state frictional healing upon stress/velocity perturbations. Dynamic permeability increase scales with the pore pressure magnitude and fracture sealing controls the following per-pulse permeability increase, both in the absence and presence of reactivation. However, initiation of the injection-induced reactivation results in a significant increase in the rate of permeability enhancement (dk/dp). These results demonstrate the role of frictional healing and sealing of fractures at interplay with other probable processes in pore pressure-driven permeability stimulation, such as particle mobilization.

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Permeability Evolution at Various Pressure Gradients in Natural Gas Hydrate Reservoir at the Shenhu Area in the South China Sea

Energies ◽

10.3390/en12193688 ◽

2019 ◽

Vol 12 (19) ◽

pp. 3688 ◽

Cited By ~ 4

Author(s):

Lu ◽

Xia ◽

Sun ◽

Bian ◽

Qiu ◽

...

Keyword(s):

Pressure Gradient ◽

Pore Structure ◽

Gas Hydrate ◽

Gas Production ◽

Pressure Gradients ◽

Permeability Evolution ◽

Shenhu Area ◽

Evolution Law ◽

Hydrate Reservoir ◽

Clayey Silt

The sediment of the hydrate reservoir in the Shenhu Area is mainly clayey silt. Its characteristic small particles and poor cementation challenge the quantification of the reservoir permeability during gas production. An accurate description of the seepage mechanism of the clayey-silt reservoir is the basis, and also a difficulty, of effective development of gas in the South China Sea. In this study, four sets of water seepage experiments under different pressure gradients are carried out using the clayey-silt reservoir sediments, in which the fourth sample was subjected to computed tomographic (CT) scans. The experimental results shows that the clayey-silt reservoir has a compression of the pore structure and decreasing permeability with the increasing pressure gradient. CT images are used to show the reduction of pore spaces for fluid flow. When the pressure gradient is less than 3 MPa per meter, the pore structure of the reservoir has minor changes. When the pressure gradient is greater than this value, the pore structure of the reservoir will be quickly compressed. This leads to a rapid decrease in permeability, and the process of permeability reduction is irreversible. The decrease of permeability can be predicted directly by establishing a power law model with the change of porosity. Our experimental results preliminarily reveal the dynamic evolution law of pore structure and permeability of clayey-silt reservoir in the process of gas hydrate exploitation via depressurization. The permeability evolution law at various pressure gradients provides a scientific and reasonable basis of a productivity control system for clayey-silt gas hydrate in depressurized gas production.

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The Key Factors That Determine the Economically Viable, Horizontal Hydrofractured Gas Wells in Mudrocks

Energies ◽

10.3390/en13092348 ◽

2020 ◽

Vol 13 (9) ◽

pp. 2348 ◽

Cited By ~ 1

Author(s):

Syed Haider ◽

Wardana Saputra ◽

Tadeusz Patzek

Keyword(s):

Gas Flow ◽

Horizontal Well ◽

Source Term ◽

Organic Matrix ◽

Fracture Network ◽

Gas Production ◽

Fracture Permeability ◽

Gas Wells ◽

Stimulated Reservoir Volume ◽

Well Production

We assemble a multiscale physical model of gas production in a mudrock (shale). We then tested our model on 45 horizontal gas wells in the Barnett with 12–15 years on production. When properly used, our model may enable shale companies to gain operational insights into how to complete a particular well in a particular shale. Macrofractures, microfractures, and nanopores form a multiscale system that controls gas flow in mudrocks. Near a horizontal well, hydraulic fracturing creates fractures at many scales and increases permeability of the source rock. We model the physical properties of the fracture network embedded in the Stimulated Reservoir Volume (SRV) with a fractal of dimension D < 2 . This fracture network interacts with the poorly connected nanopores in the organic matrix that are the source of almost all produced gas. In the practically impermeable mudrock, the known volumes of fracturing water and proppant must create an equal volume of fractures at all scales. Therefore, the surface area and the number of macrofractures created after hydrofracturing are constrained by the volume of injected water and proppant. The coupling between the fracture network and the organic matrix controls gas production from a horizontal well. The fracture permeability, k f , and the microscale source term, s, affect this coupling, thus controlling the reservoir pressure decline and mass transfer from the nanopore network to the fractures. Particular values of k f and s are determined by numerically fitting well production data with an optimization algorithm. The relationship between k f and s is somewhat hyperbolic and defines the type of fracture system created after hydrofracturing. The extremes of this relationship create two end-members of the fracture systems. A small value of the ratio k f / s causes faster production decline because of the high microscale source term, s. The effective fracture permeability is lower, but gas flow through the matrix to fractures is efficient, thus nullifying the negative effect of the smaller k f . For the high values of k f / s , production decline is slower. In summary, the fracture network permeability at the macroscale and the microscale source term control production rate of shale wells. The best quality wells have good, but not too good, macroscale connectivity.

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Impact of Various Parameters on the Production of Coalbed Methane

SPE Journal ◽

10.2118/162722-pa ◽

2013 ◽

Vol 18 (05) ◽

pp. 910-923 ◽

Cited By ~ 17

Author(s):

Zhongwei Chen ◽

Jishan Liu ◽

Akim Kabir ◽

Jianguo Wang ◽

Zhejun Pan

Keyword(s):

Time Constant ◽

Coalbed Methane ◽

Dominant Role ◽

Gas Production ◽

Fracture Permeability ◽

Permeability Model ◽

Gas Desorption ◽

Desorption Time ◽

Matrix Blocks ◽

Cbm Production

Summary Coalbed-methane (CBM) reservoirs are naturally fractured formations, comprising both permeable fractures and matrix blocks. The interaction between fractures and matrix presents a great challenge for the forecast of CBM reservoir performance. In this work, a dual-permeability model was applied to study the parameter sensitivity on the CBM production, because the dual-permeability model incorporates not only the influence from matrix and fractures but also that between adjacent matrix blocks. The mass exchange between two systems is defined as a function of desorption time constant at the standard condition, coal matrix porosity, and the difference of gas pressure between two systems. Correspondingly, gas diffusivity in matrix is considered as a variable and represented by a function of shape factor, gas desorption time, and reservoir pressure. These relations are integrated into a fully coupled numerical model of coal geomechanical deformation and gas desorption/gas flow in both systems. This numerical approach demonstrates the important nonlinear effects of the complex interaction between matrix and fractures on CBM production behaviors that cannot be recovered without rigorously incorporating geomechanical influences. This model was then used to investigate the sensitivity of CBM extraction behavior to different controlling factors, including gas desorption time constant, initial fracture permeability, fracture spacing, swelling capacity, desorption capacity, production pressure, and fracture and matrix porosities. Modeling results show that the peak magnitudes of gas-production rate increase with initial fracture permeability, sorption and swelling capacities, and matrix porosity, and decrease with gas desorption time constant and production pressure. These results also show dramatic increase in gas-production efficiency with decreasing magnitudes of fracture spacing. The comparison of the transient contributions of the desorbed gas and the free phase gas from the matrix system to gas production shows that the free phase gas plays the dominant role at the early stage, but diminishes when the adsorption phase gas takes over the dominant role, indicating the necessity of incorporating free phase gas impact in simulation models. The numerical model was also applied to match the history data from a gas-production well. A better matching result than that for the single-permeability model demonstrates the potential capability of the dual-permeability model for the forecast of CBM production.

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Electrical conductivity of brine‐saturated fractured rock

Geophysics ◽

10.1190/1.1442209 ◽

1986 ◽

Vol 51 (8) ◽

pp. 1585-1593 ◽

Cited By ~ 25

Author(s):

R. M. Stesky

Keyword(s):

Electrical Conductivity ◽

Fracture Surface ◽

Contact Area ◽

Fractured Rock ◽

Flow Path ◽

Fracture Plane ◽

Fracture Aperture ◽

Height Distribution ◽

Surface Geometry ◽

Path Tortuosity

A theoretical analysis shows that electrical conductivity along fractures in a saturated porous rock is a function of many factors: fluid and rock conductivities, initial fracture aperture and contact area, fracture surface geometry (asperity height distribution and tip curvature), elastic moduli of the rock, and confining pressure or normal stress acting across the fracture. The conductivity in the fracture plane decreases approximately in proportion to log pressure, but the conductivity is influenced by the increased contact area, and hence flow‐path tortuosity, along the fracture surface at elevated pressures. Electrical conductivity in fractures is more affected by flow‐path tortuosity than is permeability. The dependence on pressure was tested using laboratory measurements of conductivity through split cores containing ground, saw‐cut surfaces in a variety of rocks under confining pressures to 200 MPa. The conductivity decreased approximately in proportion to log pressure (there was little effect of increased contact area, and hence tortuosity), which suggests that the contact area may not exceed a few percent of the total apparent area. Measurements of gas permeability through the same split cores showed that when the asperity deformation remained largely elastic, permeability and conductivity had a power of 3 relationship. When asperity collapse occurred, as in a dolomitic marble, the powerlaw relation no longer held; permeability decreased more rapidly under pressure than did conductivity. The different influences of porosity and flow aperture may account for the different behaviors of the two transport properties. The theory suggests a number of ways in which fracture parameters may be extracted from field data. Some of the methods rely on the scale dependence and pressure dependence of the fractured‐rock conductivity; other methods require correlating between different physical properties, such as seismic velocity, which are influenced by the presence of fractures.

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