Rock Permeability Research Articles

NMR relaxometry – a new reliable and non-destructive method to estimate the fluid content of rock salt

Abstract. In the context of the site selection procedure for a high-level radioactive waste repository in Germany (StandAG, 2017), the fluid content of salt rocks is an important parameter to evaluate their barrier properties, i.e. the potential for gas formation (geoscientific weighing criteria 7 – geoWK-7) and the tendency to form fluid pathways (geoWK-6). Moreover, it can affect hydraulic conductivity (minimum requirement 1 – MA-1, geoWK-1 and geoWK-11), heat resistance (geoWK-8) and rock mechanical properties (geoWK-5), and it can be used for the spatial characterisation (geoWK-3) of the host rock (e.g. Kneuker et al., 2020). Fluids in rock salt (halite) are typically present in small, unconnected inclusions (commonly < 25 µm) located within crystals or arranged along crystal boundaries and fissures, and they can consist of brine, minor amounts of gases and hydrocarbons. When estimating the fluid content of rock salt, the main challenges are (i) the low fluid content (< 1 wt %), (ii) the low permeability of the bulk rock preventing fluid extraction and (iii) the spatial heterogeneous fluid distribution. In summary, the measurements are time intensive, and the results are highly dependent on the sample selection and preparation. Nuclear magnetic relaxation (NMR) relaxometry is an established petrophysical method in the oil and gas industry for the non-invasive characterisation of hydrocarbon host rocks and their fluids (e.g. Dunn et al., 2002), but it has not been used extensively for rock salt to date. We present the first results obtained from steeply inclined Zechstein rock salt (z2HS2) and compare them with a water content estimated by extensive grinding (< 30 µm) of the salt samples in dried acetone and the subsequent analysis of the extracted fluids using infrared spectroscopy (Mertineit et al., 2022). The first results show that NMR has promising features including (i) a low limit of detection (∼0.01 wt %), (ii) non-destructive and (iii) quick (5–10 min) measurements, (iv) no need for extensive sample preparation, and (v) the provision of an average fluid content over a large sample volume (100–900 mL).

A seismic-reflection-based approach for determining the hydraulic permeability of rocks in a subsurface region

Abstract. The hydraulic permeability of rocks characterizes fluid mobility in the pores of underground reservoirs. Accurate information on this quantity is important for various geotechnology applications with urgent social, environmental and political significance (e.g., the exploration, optimization and monitoring of underground disposals of gases, fluids and radioactive wastes; safe underground engineering operations; and the exploration and development of geothermal and hydrocarbon energy). Because of the high resolution and large penetration range of seismic waves as well as the ability of seismic exploration to operate from the Earth's surface, a seismic-reflection-based method for characterizing underground permeability is very important. The elastic properties of rocks of a given lithology are strongly influenced by the compliant pore space. However, the hydraulic permeability of such rocks can be controlled by compliant pores, stiff pores or both types of pores. Using stress-dependent rock-physics experiments, we derive models of elastic properties (e.g., seismic velocities) as functions of compliant and stiff pore-space geometries. Simultaneously analyzing the stress-dependent behavior of the porosity and of the permeability, we identify which part of the pore space controls the permeability – compliant and/or stiff pore space – and derive a corresponding model. These models are used to directly characterize stiff and compliant pore spaces from seismic velocities and to calculate the underground permeability.

Determination of the in situ hydraulic parameters of the Callovo–Oxfordian clay rock in a long-term hydraulic interference testing at Andra's Underground Research Laboratory (CMHM)

Abstract. Between 2009 and 2015, Andra has conducted a unique long-term hydraulic interference test in two parallel boreholes 1 m apart from each other and air core drilled in the undisturbed Oxfordian Clay rock at Andra's Underground Research Laboratory (CMHM) in Bure, France. The experimental set-up consisted of six test intervals positioned along the parallel boreholes drilled from a drift located within the Callovo–Oxfordian clay at around 500 m b.g.l. (below ground level). The 20 m boreholes were oriented around 30∘ downwards. The pressure sensors linked to six intervals of 1 m length each allowed for continuous pressure measurement over 6 years and a slanted borehole for the observation of rock displacements (see Fig. 1). Additionally, flow rates were measured during water injection tests that lasted weeks or months. This extensive set of hydraulic data allowed, for the first time, a precise determination of the in situ Callovo–Oxfordian clay rock permeability and anisotropy and its specific storage at the metre to decametre scale. It was achieved based on an automated calibration, using a 3D flow model and explicitly considering all the relevant hydraulic elements acting on the flow system (such as rock mass, borehole disturbed zone and sealing elements) and the drift acting as a steady sink due to the underground ventilation (see Fig. 2). The history matching was performed on the transient pressure measurements. The obtained numerical calibration results were in close agreement with the hydraulic parameter values of the Callovo–Oxfordian clay determined at a smaller scale (single borehole tests and rock core samples in the laboratory), therefore demonstrating the reliability of the very low permeability of the Callovo–Oxfordian clay at the metre to decametre scale. Furthermore, the modelling illustrated the impact of the measurement set-up and its details on the observed hydraulic behaviour. The analysis methodology and the main findings will be presented.

Challenges for geomechanical laboratory analyses of claystones with regard to the time frame of the site selection process

Abstract. The current programme for the site selection process in Germany schedules 11 months for geomechanical laboratory tests per potential future site (BGE, 2022). For the laboratory analysis of rock salt, this time frame seems realistic as no hydromechanical coupling has to be taken into account. In the case of a crystalline basement, the intact rock matrix is low permeable, but transport processes are dominated by ubiquitous fracture networks, which are hard to capture in laboratory settings. Thus, the effect that hydromechanical coupling in low permeable rock has on the speed of laboratory measurements will probably be no problem. However, for claystones, the geomechanical processes within the rock matrix strongly depend on the hydromechanical coupling, which thus determines the speed with which, for example, loading ramps can be applied in the laboratory. The need to maintain the pore pressure equilibrium during the experiments in order to know the acting effective stresses slows down the speed of the measurements significantly. Given the tight time frame of 11 months and the numerous parameters which have to be analysed according to law (StandAG, 2017), the low speed with which the experiments can be performed represents a severe hindrance. It is thus important to establish measurement protocols which enable the simultaneous determination of several parameters in order to save time. Based on our experience with experiments on Opalinus Clay, we offer a first idea of how such a measurement protocol could look and would like to invite a discussion on how to optimise experiments on claystones further in order to have a chance to meet the very tight time frame required by the site selection process.

Characterising a rock fracture rough surface using spatial continuity and kriging: a new approach to meshing coupled thermo–hydraulic–mechanical–chemical (THMC) models

Abstract. Fluid flow through low permeability rocks is mainly accomplished through fractures. In order to model fluid flow, coupled thermo–hydraulic–mechanical–chemical (THMC) numerical models are used, which rely on fracture surface representations to construct a distribution model of the empty space (aperture) between the two fracture faces. The traditionally used statistical representations of fracture surfaces often overlook spatial continuity (SC), i.e. how well correlated points are in direction and distance. Examples are the fractures' aperture distribution random sampling to the joint roughness coefficient. This may result in a poor representation of the aperture distribution and thus a poor model. The first aim of this study is to investigate the possibility of characterising a fracture surface roughness using its SC parameters, an upscaled fracture surface and ordinary kriging (OK) interpolation algorithm. This method provides better control over the aperture model creation, which will have implications for its complexity and computation times. The second aim is to utilise the SC information and the distribution of a fracture in order to extrapolate (i.e. blind predict) the distribution of the fracture where no observations exist. A statistical analysis was performed in a greywacke in order to acquire the parameters necessary to describe the SC of the fracture surface topography. The surface was then interpolated using the OK algorithm. These parameters and the surface distribution will be used to inform the OK algorithm to extrapolate the fracture to where no data has yet been acquired. A reasonable match between the kriged and original surfaces has been achieved and the fit quantified by analysing the error between the two and by R2, which offer positive measurements of methodological quality. The aperture can easily be calculated from the difference between both complementary surfaces. The aperture between the two original fracture surfaces versus the two kriged fracture surfaces was also quantified and compared, yielding good results. This method may provide a new alternative to current storing and computing solutions for fracture representation, especially in aperture distribution calculation for coupled THMC numerical models and simulations. To verify advances in accuracy and computing times for this method, results between models derived from the original versus kriging aperture data will have to be compared. Another potential applicability of the SC information is to know a priori from any modelling which directions are those of Darcy's flow and which are the directions of the highest and lowest dilation rates with shearing, which will have to be confirmed with future planned modelling work.

Seepage-stress combined experiment and damage model of rock in different loading and unloading paths

In the excavation of water-related underground projects such as hydropower and energy reserves, the surrounding rock surfers complex stress path and stress state redistribution, resulting in damage and failure under the hydro-mechanical coupling condition. However, the rock hydro-mechanical coupling characteristics under complex stress paths are unclear and corresponding theoretical models are scarce. In this study, a series of tests such as triaxial compression, unloading confining pressure and cyclic loading and unloading were carried out to study the effects of different stress paths, stress levels and seepage pressure on rock deformation, strength, failure and permeability. Based on test results, the damage evolutions under three different testing paths were analyzed, a new seepage-stress coupling statistical damage model which can better simulate the compaction stage is proposed. The prediction results of the proposed model under different stress paths are in good agreement with the experimental results. Under different stress paths, the fitting relationship between parameters R0 and n and σeff is similar and has good correlation.

Plurigaussian conditional simulation (PGS) of the Budenovskoe uranium roll-front deposit, central Kazakhstan: 3D model of the host sedimentary sequence

ABSTRACT The current paper presents case study of the Budenovskoe sandstone-hosted uranium deposit, the host sequence of which has been modelled geostatistically, using Plurigaussian conditional simulation (PGS) and Sequential Gaussian conditional simulation (SGS). The PGS method minimises subjectivism of the geological interpretations, by constraining the lithological models to geostatistical and lithostratigraphic characteristics of the host sequence, and accurately reproduces litho-stratigraphy of the sedimentary sequence, realistically conveying its complexity. This was integrated with the rock permeability generated using SGS. Integrating two models has significantly enhanced definition of the fluid infiltration passages in the host sequence. The model was built using stochastic algorithms of PGS and SGS, and therefore can be used for estimation the project risk. In practice, the errors, initially estimated to the blocks used for the conditional simulation, are grouped to the volumes of a practical interest, including the resource and reserve domains, production blocks and the leach cells.

Effects of ultrasonic oscillations on permeability of rocks during the paraffinic oil flow

The paper shows that depending on the degree of blockage of the pore space due to paraffin precipitation the ultrasonic treatment has different effects. If a part of permeable channels is irreversibly deteriorated, then the activation of elastic oscillations contributes to postponing the moment of blocking the remaining part and helps to maintain the oil flow through a sample at a constant level. Without additional means an ultrasonic treatment does not have a significant effect in the case of strong blockage of permeable channels. If elastic oscillations are imposed on the rock and liquid at the initial moment of flow, then the porous space of the rock will be preserved from the precipitation of paraffins.

Numerical Investigation of Influential Factors in Hydraulic Fracturing Processes Using Coupled Discrete Element‐Lattice Boltzmann Method

AbstractHydraulic fracturing is widely used to stimulate unconventional reservoirs, but a systematic and comprehensive investigation into the hydraulic fracturing process is insufficient. In this work, a discrete element‐lattice Boltzmann method is implemented to simulate the hydro‐mechanical behavior in a hydraulic fracturing process. Different influential factors, including treatment parameters (injection rates and fluid viscosity), formation parameters (in situ stress states and natural fractures) and rock properties (heterogeneity of rock strengths and rock permeability), are considered and their impacts on the initiation and propagation of hydraulic fractures are evaluated. A higher injection rate, increased viscosity, and larger in situ stress will lead to an increase in the initiation pressure. Conversely, higher formation permeability and a greater degree of heterogeneity in bond strengths will result in a decrease in the initiation pressure. The complexity of generated fractures is significantly influenced by the injection rate and degree of heterogeneity. However, fluid viscosity, in situ stress states, and formation permeability individually do not affect the geometrical complexity. Shear displacement can occur during a hydraulic fracturing process due to increased pore pressure and variations in in situ stress caused by injected fluid. Low‐viscosity fluid with a high injection rate can have a significant pressure buildup and generate complex fracture networks in low‐permeability heterogeneous formations. Natural fractures can significantly impact the complexity of generated fractures, while more in‐depth research is required regarding complex natural fracture distributions.

A Convenient Device to Measure the Permeability of Intact Rock (Heterogeneity and Anisotropy)

Abstract The permeability of intact rocks affects a wide range of natural and engineered systems, yet its measurement remains costly and involves time demanding test protocols. Gas permeameters may improve efficiency but involve a complex series of pore-scale processes. In addition, peripheral damage during coring and the jacket-rock interface create a preferential flow path that affects the inferred permeability. We present a convenient permeameter for liquid-based permeability measurements using an unjacketed disk specimen. The test configuration minimizes peripheral flow bias and expedites testing times. The permeameter uses readily available devices for pressure and flow rate measurement/control and can be readily configured to measure rock permeability across six orders of magnitude. Preliminary numerical simulations allowed us to optimize the test design, to extract coefficients for data correction, and to process data to recover permeability anisotropy. The system is experimentally verified against industry standards and used to test cleaning protocols to remove fines left on the specimen surface after specimen preparation; these fines may cause clogging at the inlet phase—a bias that affects all permeameters.

Strength, deformability and permeability of kakiritic rocks from the Gotthard base tunnel

Strength, deformability and permeability of kakiritic rocks from the Gotthard base tunnel

The Nature of the Puchezh-Katunki Impact Structure (the Central Part of the East European Platform): Results of the U‒Th‒Pb Isotope System Study of Detrital Zircons from Explosive Breccias

The Puchezh-Katunki crater is located in the central part of the East European Platform in the area of the Gorky Reservoir, has a diameter of ~80 km and is morphologically expressed by the central uplift of the basement (Vorotilov knoll) and the ring depression surrounding it, on the periphery of which there is a ring terrace. The crater is filled with various coptogenic (explosive (?)) formations – breccias of various types, bodies of suvites and tagamites. The results of studying the U‒Th‒Pb isotopic system of detrital zircon grains from variegated explosive Puchezh breccias in the northwestern part of the ring terrace (three samples) are presented. The weighted average of the three youngest U‒Pb datings of detrital zircon from all studied samples is 258 ± 7 Ma, which corresponds to the Late Permian. We took this dating as the lower age limit of the Puchezh breccias. A comparison of the age sets of detrital zircon grains from the samples studied by us and from (i) crystalline rocks of the Vorotilov knoll and ring depression suvites and (ii) Upper Permian–Lower Triassic sandstones of the Zhukov ravine reference section (Moscow syneclise) was carried out. The absence among the detrital zircon from the Puchezh breccia grains, whose U‒Th‒Pb isotopic system is comparable with the parameters of zircon from the rocks of the Vorotilov knoll and suvites, indicates the local nature of the Puchezh-Katunki explosion, in which the impact-thermal impact did not affect the detrital zircons in rocks of the marginal part of the annular terrace of the crater. The high similarity of the sets of ages of detrital zircon grains from the lens of redeposited sandstones of the Puchezh breccias and Upper Permian rocks of the Zhukov ravine section indicates that the Puchezh breccias were formed mainly due to the recycling of the Upper Permian–Lower Triassic sequences underlying the explosive formations. We consider the Uralides paleoorogen as the main source for the deposits of the central regions of the East European Platform in the stratigraphic interval close to the Permian–Triassic boundary. The deposits were formed as a result of a high degree of mixing and averaging of clastic material of sedimentary flows containing the Uralian and Asha provenance signals.

Permeability Estimation for Upper Shale Member in Southern Iraqi Oil Field Using Machine learning and Hydraulic Flow Units Methods

Permeability estimation in the Upper Shale Member is rather complex due to the heterogeneity. Conventional logs do not provide permeability directly, but the core data does. Core operations and analysis processing are all costly. An alternative method is used by dividing the reservoir rock into groups (rock types) with similar characteristics in porosity and permeability for cored wells. These identified groups for the core wells can be applied to the uncored wells to predict their groups and permeabilities. Four wells were used in this study: one cored well and three uncored wells. Two classification methods of rock types were used; the first is the machine learning method (supervised and unsupervised), a new technics invention, and the second method is the hydraulic flow unit. Four groups were selected by using Machine Learning and hydraulic flow unit methods. A regression equation for each rock type was obtained to predict permeability. Then, establishing a relationship between the results of the core data groups and the logs' responses for the core well is referred to as "correlation," which is training the logs that provide an estimating model. A validation check was completed by comparing the rock type and permeability estimation from the core with the rock type and permeability estimation from the logs, which were highly matched. Finally, The rock type and permeability can be estimated for the uncored wells using only the logs that were learned from the generated training data set for the cored wells. Due to the use of more than one model to predict permeability, it was clear that one was more compatible than the other. The flow zone indicator, a classical method, still has a better rock type and permeability estimation than the new techniques, which use data mining and mathematical algorithms on a clustering basis.

Evaluating the accuracy of liquid permeability measurements in shale and tight rocks using transient flow method and comparison with gas permeability

The transient flow method for measuring permeability to liquid is a useful technique for shale and tight rocks; however, it is not as popular as the steady-state method in these rocks. One of the issues is the lack of clarity on a key term of compressibility of the fluid and rock system. Various forms of compressibility have been used in literature, which can lead to inconsistent results of liquid permeability. Using gas for the permeability measurement is more common in shale, and the Klinkenberg corrected permeability is often used to represent liquid permeability; however, how the Klinkenberg permeability is compared to liquid permeability in shale or tight rocks is not adequately addressed. This paper presents a study using the transient flow method for water and oil permeability measurement in three Eagle Ford Shale samples. Gas permeability was also measured for these samples. Different forms of the total compressibility of the fluid-rock system (Ct) are summarized from literature, and a new form of Ct is proposed. The accuracy of the calculations based on different forms of Ct is evaluated through the comparison between water and oil permeabilities and the comparison with gas permeability. The results are also compared with oil permeability obtained from the steady-state method. The new form of Ct provided the most accurate results, whereas the other forms of Ct led to errors. However, for samples with bulk compressibility of less than 1 × 10−7 psi−1, the error using those forms of Ct was negligible. The study also found that the Klinkenberg permeability obtained from the linear extrapolation is larger than the oil permeability for two samples by 12% and 37%, respectively, whereas it is smaller than the oil permeability for the other sample. This comparison suggests that a nonlinear gas slippage effect may exist in the high pressure range (>2000 psi) for shale or tight rock samples.

Reactive flow of microemulsion-based EDTA fluid for carbonate stimulation

Traditional methods for stimulating carbonate formations primarily rely on the use of highly reactive acids, such as hydrochloric acid (HCl), to create wormholes. However, the limitations of this approach in certain scenarios have prompted the exploration of alternative strategies. In this study, we investigate the synergistic potential between microemulsion and ethylenediaminetetraacetic acid (EDTA) for stimulating carbonate formations. Microemulsion systems were formulated using a nonionic surfactant, sec-butanol as a cosurfactant, xylene as the oily phase, and an aqueous solution of EDTA as the water phase. The microemulsions were characterized by phase equilibrium and rheological behavior. Coreflooding and static dissolution experiments were performed. We employ microCT imaging to evaluate the change in porosity in static dissolution experiments. The results reveal that microemulsions containing EDTA presented remarkable stability and were able to significantly enhance carbonate rock permeability up to 85%, indicating that dissolution occurred and the rock was stimulated. Analyses of microCT images on static dissolution experiments of Indiana limestones in reactive microemulsions indicate an increase in porosity, confirming the dissolution process. These findings highlight the synergistic effect of EDTA in microemulsion media for enhancing the rock permeability of carbonate formation as an alternative as low reactive system.

Analysis of aquifers zones using aeromagnetic and satellite gravimetric data in Grijalva and Usumacinta basins, Mexico

The purpose of this study is to characterize the magnetic and gravity responses of the subsurface in the Grijalva and Usumacinta Basins of southeastern Mexico, to identify and define areas of rock units with aquifer potential. For this purpose, aeromagnetic and gravimetric satellite data were processed to delimit the geological features of greatest interest. The results show that the central-northern part of the study area corresponds to the zone with the greatest aquifer potential and coincides with the areas of greatest sedimentary thickness and where groundwater concessions are concentrated. The gradients between the magnetic and gravity responses help to identify the structural framework, including faults, fractures, edges, and geological contacts, and to infer the regions with aquifer potential. Among the transforms or filters used, the Tilt Derivative (TDR) exhibits the linear trends associated with the structural framework of hydrological interest. The work delimited permeable rock units present in the study area; however, it is important to continue with other studies focused on direct exploration and research techniques such as geological, lithological, and hydrogeological mapping, as an additional method of validating results gotten. The study aims to contribute to decision-making and research on geohydrological issues, land use planning, and related public policies.

Influence of fracture pattern between Hot Sedimentary Aquifer (HSA) and Enhanced Geothermal Systems (EGS) on thermal production and permeability evolution

Thermal energy extraction relies on the fluid circulation and heat transfer between fluids and rock matrix. The conductive fracture channel provides effective conduits for fluid circulation, while absorbing heat energy from adjacent blocks depending on heat transfer length. The vertical depth variation not only leads to the quality of heat reservoir, but also brings substantial influence on fracture pattern due to stress state and chronological tectonic evolution. Consequently, it is vital to explore the influence of fracture pattern on the model of thermal energy production and subsequent permeability evolution. The induced thermal stress plays an important role in the stress state and fractures and therefore permeability development. It is hypothesized that the two-stage evolution of permeability and porosity: shrinkage effect from thermal cooling is strong sufficient with the highest drawdown gradient, which leads to significant minimum horizontal stress reduction and permeability enhancement. The second stage when rock temperature completely drained allows permeability and porosity reduce to the initial magnitude, with the thermal stress diminishes. The shallow geothermal extraction with less consolidation induces less thermal stress to change rock permeability and porosity. Therefore, the thermal stress needs to be taken into account in evaluating the formation properties evolution and stress state.

Physics-Based Modeling to Understand and to Propose Forecasting Methods of Induced Seismicity

Abstract Induced seismicity compromises the widespread deployment of geoenergy applications that contribute to mitigate climate change. In particular, the development of Enhanced Geothermal Systems (EGS) has been hindered by the risk of induced seismicity, mostly caused by hydraulic stimulation aimed at enhancing the permeability of deep hot crystalline rocks. Injection-induced seismicity has been traditionally attributed to fluid pressure buildup, which destabilizes fractures and faults. However, the largest seismic events commonly occur after the stop of injection, when pore pressure drops and both the magnitude and frequency of induced seismicity is expected to decrease. This counterintuitive phenomenon is not well understood. Yet, understanding the triggering mechanisms is the key to reliably forecast and manage induced seismicity. Here, we investigate the triggering mechanisms of co- and post-injection seismicity using coupled hydromechanical models, considering both a homogeneous and a fault-crossed domain, based on the case of Basel EGS (Switzerland). We find that the combination of pressure diffusion, poroelastic stressing, and static stress transfer explains the occurrence of induced seismicity, especially after the stop of injection, significantly better than the pore pressure alone. Considering a fault zone, which is more permeable and deformable than the surrounding rock, amplifies pressure diffusion along the fault and causes anisotropic variations of the stress field that lead to an increase in the seismicity rate that is orders of magnitude larger than for the homogeneous domain. These results point out that identifying the main geological structures through subsurface characterization is key to improve physics-based induced seismicity forecasting.

An optimization method for equivalent bulk permeability of gas shale matrix with crushed samples and re-recognition of the influence of pressure and particle size

The pressure decay (or gas expansion) test with crushed samples has been used to evaluate the matrix permeability of shale and other low-permeability rock for many years. However, there still exist uncertainties relating to particle size and equilibrium pressure. The existing late-stage curve fitting method has the advantage of easy calculation, but the assumption that gas enters particles with a single permeability value is not generally applicable for shale samples, and late-stage analysis may lead to underestimation. This study proposes an optimization method to determine the equivalent bulk permeability that ensures the smallest sum of squares of errors between the forward-predicted pressure decay curve and the measure one. Both the optimization and curve fitting method are applied to two shale samples from the Ordovician Wufeng Formation of two wells in the Sichuan Basin, China with improved apparatus and testing procedures. The optimization method is superior to the curve fitting method in the repeatability and regularity on the change of apparent permeability with pressure. A strong linear relationship between apparent permeability and coefficient of compressibility is established between 3 and 12 bars. The variation of permeability with particle size is more diverse than that is commonly understood and might be nonmonotonic, depending on the change of pore structure during crushing. Change of apparent permeability with pressure (non-Darcy feature) is proposed as a criterion of whether pore structure has changed significantly. It is suggested to measure the variation of permeability with pressure and particle size to obtain a more comprehensive understanding of matrix permeability and pore structure.

Theoretical Developments for the Interpretation of Cavity Flow Permeability Tests Conducted on Intact Lac du Bonnet Granite

The permeability of intact geologic media features prominently in many geo-environmental endeavours. The laboratory estimation of permeability is an important adjunct to the field estimation of bulk permeability values, which involves a great deal of supplementary in situ investigations to correctly interpret field data. Laboratory permeability estimation is also a viable method if core samples are recovered from in situ geological mapping of the region under study. The basic methodologies for permeability estimation rely on either steady-state or transient tests of the geologic material depending on the anticipated permeability value. This paper presents a steady flow test conducted on a partially drilled cavity located on the axis of a cylindrical specimen. Certain compact theoretical relationships are proposed for the estimation of steady flow from a cavity of finite dimensions located along the axis of a cylindrical specimen. The relationships are used to estimate the permeability of a cylinder of Lac du Bonnet granite obtained from the western flank of the Canadian Shield. The results from the cavity flow permeability experiments are compared with other estimates for the permeability of granitic rocks reported in the literature.