Low-permeability Rocks Research Articles

Isotope diffusive exchange experiments for deriving porewater isotope composition in low-permeability rocks – Improvements in experimental procedure and data processing

Over the last decades, several methods have been developed for determining the porewater stable isotope composition (δ2H, δ18O) in low-permeability, argillaceous rocks and pertinent to the acquisition of spatially highly-resolved tracer profiles for investigating subsurface transport processes over large scales of time and space. One of these methods is the so-called isotope diffusive exchange technique (IDE) where the porewater of the rock equilibrates via the vapour phase with a test water of known isotope composition. In this study we aim for 1) identifying and assessing important parameters and artefacts these experiments are sensitive and prone to, respectively, 2) evaluating their impact on the porewater isotope composition derived from such experiments and 3) testing the reproducibility and accuracy of the method. For this, the experimental data and the calculated porewater isotope composition of 752 isotope diffusive exchange experiments, performed on drillcore samples from variable lithologies, were examined under these aspects. The investigations are complemented by comparison between porewater and groundwater isotope values in regions of water-conducting zones and an interlaboratory comparison. Ultimately, this allowed defining a stringent procedure for the evaluation of the experimental data and classifying experiments as ‘reliable’, less reliable’ and ‘failed’. For calculating the porewater isotope composition, a new approach was developed that accounts for sample-scale heterogeneity of the water content. This procedure of data evaluation and processing resulted in smooth isotope profiles with only little scatter across largely different lithologies. The interlaboratory comparison attests the method a very good reproducibility. The comparison with groundwater isotope data reveals slightly enriched δ18O and δ2H signatures by 0.3–0.6 and 1.7–2.7‰ VSMOW, respectively, for some samples investigated by the IDE method. No stringent explanation exists at this stage for these differences, but it must be emphasized that these deviations are small compared to the typical natural variations observed in profiles of these tracers. This demonstrates that porewater isotope data obtained by the IDE method represent the conditions in the in situ porewater reasonably well when strictly following the proposed procedures of the experimental setup, the evaluation of experimental data and the calculation of porewater isotope compositions.

Vertical and lateral distribution of helium in porewater of the Mesozoic sedimentary sequence of northern Switzerland – A comparative investigation across multiple boreholes

Helium concentrations and 3He/4He ratios were measured on porewater extracted from the low-permeability rock matrix and groundwater in bounding aquifers in Northern Switzerland. The samples were collected from six deep boreholes, which were drilled across the Tertiary Molasse and the underlying Mesozoic sediments at three different study areas within the context of Nagra's deep drilling programme for the underground disposal of radioactive waste. Porewater helium data obtained from each borehole at high spatial resolution describe continuous profiles over multiple aquifer-aquitard intervals across the Jurassic to Triassic sediment sequence. Given the lateral distribution of the investigated areas (∼20 km apart) and having two boreholes in each area (a few km apart), this allows to investigate both vertical and lateral changes of He in the porewater and groundwater system at high resolution and over large scales.In the about 300–400 m thick Dogger–Lias aquitard sequence including the Opalinus Clay, porewater He concentrations are nearly identical and have very similar 3He/4He signatures in all boreholes. This suggests a common history in the development of these systems despite the boreholes being located in three study areas with different hydrogeological setting and tectonic history since their last burial and diagenesis. Proximal to the groundwaters, He profiles show that the porewater system is controlled by diffusive redistribution of in-situ produced He from high concentrations in the aquitards towards lower concentrations in the bounding groundwaters. At some locations, the influence of evaporitic strata with very low diffusivity acting as transport barriers becomes obvious. Close to the aquitards, differences between the profile shapes of helium and other conservative tracers such as δ2H in the different boreholes and areas indicate different boundary conditions for the different tracers over the more recent geological past, as well as, for some boreholes, the potential contribution of helium from the groundwater to the porewater in the nearby low-permeability rock matrix.In one study area, cross-formation transport of helium could be identified close to a deep reaching tectonic structure related to the Hegau-Lake Constance fault system. This basement derived gas is subsequently laterally distributed via groundwater in the different aquifers and influences the porewater of the adjacent aquitard formations, as evidenced by the helium concentrations and 3He/4He ratios in the groundwater and porewater in the two boreholes of this siting area.

Profiles of δ18O and δ2H in porewater of a Mesozoic rock sequence: Regional variability and relation to large-scale transport regimes

A large drilling campaign has been conducted across sediments of the Tertiary Molasse Basin and the underlying Mesozoic in Northern Switzerland in the context of underground disposal of radioactive waste. The ~300-400 m thick Mesozoic low-permeability rock sequence of interest is located between the regional aquifers made of Malm limestone at the top and dolomite/limestone formations of the Muschelkalk at the bottom. Locally, water-conducting zones occur in Dogger marl/limestone (Hauptrogenstein) below the Malm and/or in Keuper sandstone/dolomite above the Muschelkalk aquifer. Here we report on the distribution of the natural tracers δ2H and δ18O in porewater and groundwater from eight new boreholes in three study areas. The distribution of these tracers is the result of hydrogeological processes acting in the past, and their analysis offers unique possibilities to decode large-scale transport processes. The large data set allows us to compare the variability of δ18O and δ2H vertically as well as laterally in the three areas (∼20 km apart) and in the 2–4 boreholes in each area (a few km apart). The eight isotope profiles show many similarities, but also distinct features that are related to the lateral variation of aquifer properties, tectonic setting and topography, and the geometry of the aquifer-aquitard systems. Boundaries of the profiles are typically given by groundwater in the Malm (one location in the Dogger) and Muschelkalk aquifer, and locally by water-conducting zones in the Keuper. Maximum isotope values in the central part of the profiles plot to the right of the GMWL (Global Meteoric Water Line) to different degrees, as do values in the Malm aquifer. Towards the Keuper aquifer (if present) and the Muschelkalk aquifer, the values decrease smoothly and sharply, respectively, and approach the GMWL. The sharp decrease towards the Muschelkalk aquifer indicates a change in the isotope signature in the recent past or is related to low porosity and low diffusivity values in adjacent anhydrite layers. The two tracers δ2H and δ18O show different trends in the more central parts (almost constant or decreasing with depth, respectively). These differences are very likely inherited from pre-Pleistocene processes, i.e., before the present-day signatures in the aquifers came into play. Transport simulations are used to narrow down the timing of changes in the aquifer signatures in the more recent past (10 ka to few Ma ago). The data presented here demonstrate that (1) lateral variability is limited, even though the low-permeability zones are found at different depths, meaning that transport regimes were similar over large times of the past, (2) the known lateral variability of the Keuper aquifer is confirmed by the porewater profiles, (3) diffusion can explain the observed profile shapes and (4) signatures in the central parts of the low-permeability zone are oldest in the sense that they are furthest away from the GMWL.

Experimental Study on SiO2 Nanoparticles-Assisted Alpha-Olefin Sulfonate Sodium (AOS) and Hydrolyzed Polyacrylamide (HPAM) Synergistically Enhanced Oil Recovery

The purpose of this study is to investigate the use of SiO2 nanoparticles in assisting with surfactants and polymers for tertiary oil recovery, with the aim of enhancing oil recovery. The article characterizes the performance of SiO2 nanoparticles, including particle size, dispersion stability, and zeta potential, evaluates the synergistic effects of nanoparticles with alpha-olefin sulfonate sodium (AOS) surfactants and hydrolyzed polyacrylamide (HPAM) on reducing interfacial tension and altering wettability, and conducts core flooding experiments in rock cores with varying permeabilities. The findings demonstrate that the particle size decreased from 191 nm to 125 nm upon the addition of SiO2 nanoparticles to AOS surfactant, but increased to 389 nm upon the addition of SiO2 nanoparticles to HPAM. The dispersibility experiment showed that the SiO2 nanoparticle solution did not precipitate over 10 days. After adding 0.05% SiO2 nanoparticles to AOS surfactant, the zeta potential was −40.2 mV, while adding 0.05% SiO2 nanoparticles to 0.1% HPAM resulted in a decrease in the zeta potential to −25.03. The addition of SiO2 nanoparticles to AOS surfactant further reduced the IFT value to 0.19 mN/m, altering the rock wettability from oil-wet to strongly water-wet, with the contact angle decreasing from 110° to 18°. In low-permeability rock core oil displacement experiments, the use of AOS surfactants and HPAM for enhanced oil recovery increased the recovery rate by 24.5% over water flooding. The recovery rate increased by 21.6% over water flooding in low-permeability rock core experiments after SiO2 nanoparticles were added and surfactants and polymers were utilized for oil displacement. This is because the nanoparticles blocked small pore throats, resulting in increased resistance and hindered free fluid flow. The main causes of this plugging are mutual interference and mechanical entrapment, which cause the pressure differential to rise quickly. In high-permeability rock core oil displacement experiments, the use of AOS surfactants and HPAM for oil recovery increased the recovery rate by 34.6% over water flooding. Additionally, the recovery rate increased by 39.4% over water flooding with the addition of SiO2 nanoparticles and the use of AOS surfactants and HPAM for oil displacement. Because SiO2 nanoparticles create wedge-shaped structures inside highly permeable rock cores, they create structural separation pressure, which drives crude oil forward and aids in diffusion. This results in a comparatively small increase in pressure differential. Simultaneously, the nanoparticles change the rock surfaces’ wettability, which lowers the amount of crude oil that adsorbs and improves oil recovery.

Numerical simulation analysis of CH4 breakthrough pressure in partially saturated low-permeability rock sample under multiple P-T conditions

Breakthrough pressure of CH4 is an important parameter in shale gas exploitation and the evaluation of cap rocks. To date, many studies have been carried out to investigate CH4 breakthrough pressure based on experimental methods, meanwhile, some studies have also proposed numerical simulation theories on multiphase flow in porous media. However, there are few studies on numerical simulation methods for predicting CH4 breakthrough pressure on rock-core scale under various conditions. Therefore, in this study, we propose a numerical method that can be used to predict CH4 breakthrough pressure in partially saturated low-permeability rock sample under multiple P-T conditions based on our published experimental results. The simulative results show that both CH4 breakthrough pressure and breakthrough time are exponentially related to temperature and pressure conditions, moreover, CH4 breakthrough pressure and breakthrough time decrease with increasing temperature and pressure. Under the multiple P-T conditions in this study, the effect of pressure on numerical results is greater than that of temperature. By comparing the numerical results with the published experimental data, it has been validated that the numerical method proposed in this study is reasonable. Furthermore, we have parametrically swept 3 key properties in CH4-H2O-rock systems, namely, dynamic viscosity, density, and interfacial tension; the order of the effects of 3 properties on the CH4 breakthrough process is, dynamic viscosity > interfacial tension > density. The numerical method established in this study can provide an important reference for the prediction of gas breakthrough process in rock core and for related numerical studies and engineering practice.

A New Method for Evaluating Fracability Based on Cluster Analysis and Well Logging Petrophysical Facies Division

The fracability of rock is a crucial parameter in determining the efficiency of fracturing in tight reservoirs. However, current methods for evaluating fracability have significant limitations. This paper proposes a new method for evaluating reservoir fracability based on cluster analysis of logging petrophysical facies. This method considers rock mechanics characteristics, petrophysical response characteristics, and reservoir physical parameters, among other factors. The Well X of the block was used as the research subject. Using the brittleness index and permeability evaluation index, the reservoir fracability of the target block is classified into five categories: high brittleness and low permeability rock, high brittleness and super low permeability rock, low brittleness and low permeability rock, low brittleness and super low permeability rock, and clay/shale. Geolog software is used to generate fracability prediction profiles for representative wells based on petrophysical facies. To further validate this evaluation method, the fracture construction data and microseismic monitoring interpretation results of Well Y in a tight block of an oil field were synthesized and analyzed to predict its fracability. The overall prediction accuracy reached 81.8%, indicating that the new fracability evaluation method has good application effect.

Forecasting the occurrence of injection-induced heterogeneous slip on rock fractures

Forecasting the slip behavior of a non-uniformly pressurized, heterogeneous creeping rock fracture, either aseismic creep or dynamic slip, is challenging based solely on laboratory and field measurements. Here we reported a simple, robust method to determine whether an aseismic creep is maintained or transitions to a dynamic slip during fluid injection. We reproduced the non-uniformly distributed fluid pressure and the resulting heterogenous aseismic creep on a critically stressed fracture and revealed the ratio of shear stress and frictional resistance corresponding to the fluid pressure front reaching or exceeding unity at the occurrence of dynamic slip. The determination of frictional resistance is based on the Mohr-Coulomb failure criterion with fluid pressure and friction coefficient on discrete segments of the fracture, and the length of fluid pressure front is calculated from hydraulic diffusivity and elapsed time. We used the experimental results of 9 shale fractures and 3 granite fractures to verify this method. We can also observe how the fluid pressure front propagates until the ratio of shear stress and frictional resistance approaches unity or is constrained with the ratio far below unity. This method has the potential for rapidly forecasting the injection-induced slip on a low-permeability rock fracture and simply characterizing the slip behavior of a natural, large-scale fracture during fluid injection.

State of the art of hydraulic packer testing in clay rocks in the Swiss national radioactive waste disposal program

Abstract. To provide input for site selection and the safety case for deep geological repositories for radioactive waste, Nagra has drilled a series of deep boreholes in northern Switzerland. As part of the hydrogeological characterization of this exploratory drilling campaign, hydraulic packer tests in the sedimentary rocks were carried out under the supervision of Nagra, in depths from 300 to 1130 m b.g.l. (below ground level). Single or straddle-packer hydraulic tests were conducted in different low-permeability rocks. The hydraulic testing equipment used was specially designed to reduce uncertainty associated with the low-permeability testing conditions and included a downhole hydraulic shut-in valve (DHSIV), a hydraulic piston, a probe carrier, and inflatable packer(s). Pressure and temperature are monitored with sensors connected to the bottom of the borehole, the test interval, the annulus above the upper packer, and the test tubing above the DHSIV. Hydraulic test sequences consisted of multiple withdrawal and shut-in phases. Test phases started with a compliance phase to allow some of the pressure and temperature transients caused by tool installation and packer inflation to dissipate, followed by a pressure static recovery phase to allow the test interval pressure to establish a recovery trend after being isolated. In general, in the low-permeability formations the active test sequence consisted of a pulse withdrawal performed using a hydraulically operated piston displacing a precisely defined volume, a slug withdrawal, and lastly a slug-withdrawal shut-in phase. The pressure data collected during the hydraulic tests were analyzed using the well-test simulator nSIGHTS®. The use of a numerical model is necessary for the analyses of the tests in low-permeability rocks as borehole history and temperature equilibration during the test can have a significant impact on test responses. Analyses started with the definition of a borehole-formation conceptual flow model based on geological information and interpretation of diagnostic plots. Input model parameters composed of non-fitting parameters and fitting parameters are defined. Preliminary automated calibrations are performed to identify the appropriate conceptual model and obtain baseline estimates of the fitting parameters for each tested interval. Perturbation analyses entailing hundreds to thousands of optimizations are performed to obtain the final best-fit parameter values and the corresponding uncertainty ranges. Our presentation will give an overview on methodologies and workflows with emphasis on the numerical design and analysis techniques applied to the hydraulic packer tests performed. The applied methodology provided high-quality results and reliable estimates of the hydraulic conductivities in the low-permeability rocks. The results from the hydraulic packer tests will be presented, and implications for further research by Nagra will be discussed.

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.

Geological controls of discharge variability in the Thames Basin, UK from cross-spectral analyses: Observations versus modelling

Geological factors controlling daily- to multi-year discharge variability in 48 sub-catchments spanning 10–1000 km2 in the Thames Basin were investigated using cross-spectral analysis. The analyses represent a ‘transfer function approach’ applied to daily observed streamflow (output) versus catchment-wide precipitation (input) for data spanning 1990–2014. Catchments dominated by high-permeability bedrock have significant attenuation of high-frequency precipitation variability and large delays at all frequencies with streamflow dominated by baseflow (high lag1 autocorrelation and high Base Flow Index, BFI). Catchments dominated by low-permeability rocks have little high-frequency attenuation and small delays and consequently ‘flashy’ behaviour. For all sub-catchments >300 km2 in the Thames Basin, attenuation of the highest frequency precipitation variability caused by mixing of flow from upstream plus groundwater flow (representing ‘older’ variability) with direct surface flow (‘younger’ variability) constitutes real-world moving averaging as indicated by a roll-off in power at the highest frequencies.The success of the JULES land surface model in simulating discharge (i.e. surface and sub-surface runoff routed between grid boxes) is also linked to the underlying geology. Larger catchments (>300 km2) are modelled well because routing between numerous grid boxes leads to moving averaging that is a good analogue for the observations. Modelling was least successful (e.g. lowest Kling-Gupta Efficiency) for small catchments (<300 km2) dominated by high-permeability bedrock - with far too little attenuation of high-frequency precipitation variability and insufficient delays at all frequencies. Experimentally switching the soil saturated hydraulic conductivity to that of the underlying bedrock for grid boxes dominated by aquifers significantly improves modelled discharge variability in small sub-catchments - confirming the importance of bedrock permeability in modelling.For small catchments in data-sparse regions, knowledge of the relative proportions of different hydrogeological units (aquifers, aquitards) potentially could be used to predict and model discharge variability as characterised by BFI and lag1 autocorrelation.

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.

Multifractal estimation of NMR T2 cut-off value in low-permeability rocks considering spectrum kurtosis: SMOTE-based oversampling integrated with machine learning

The transverse relaxation time (T2) cut-off value plays a crucial role in nuclear magnetic resonance for identifying movable and immovable boundaries, evaluating permeability, and determining fluid saturation in petrophysical characterization of petroleum reservoirs. This study focuses on the systematic analysis of T2 spectra and T2 cut-off values in low-permeability reservoir rocks. Analysis of 36 low-permeability cores revealed a wide distribution of T2 cut-off values, ranging from 7 to 50 ms. Additionally, the T2 spectra exhibited multimodal characteristics, predominantly displaying unimodal and bimodal morphologies, with a few trimodal morphologies, which are inherently influenced by different pore types. Fractal characteristics of pore structure in fully water-saturated cores were captured through the T2 spectra, which were calculated using generalized fractal and multifractal theories. To augment the limited dataset of 36 cores, the synthetic minority oversampling technique was employed. Models for evaluating the T2 cut-off value were separately developed based on the classified T2 spectra, considering the number of peaks, and utilizing generalized fractal dimensions at the weight <0 and the singular intensity range. The underlying mechanism is that the singular intensity and generalized fractal dimensions at the weight <0 can detect the T2 spectral shift. However, the T2 spectral shift has negligible effects on multifractal spectrum function difference and generalized fractal dimensions at the weight >0. The primary objective of this work is to gain insights into the relationship between the kurtosis of the T2 spectrum and pore types, as well as to predict the T2 cut-off value of low-permeability rocks using machine learning and data augmentation techniques.

The Pressure‐ and Temperature‐Dependence of Thermal Pressurization in Localized Faults

AbstractThermal pressurization (TP) is predicted to be an important dynamic frictional weakening mechanism during earthquakes. The prevailing models, though, assume that the physical, thermal and hydraulic properties of the fluid‐saturated rock in the fault zone are constant during TP (the constant case) which inherently involves temperature and pressure changes. We solve the governing equations for TP in their general form with pressure‐ and temperature‐dependent physical, thermal and hydraulic parameters of a saturated fault zone with a one‐dimensional numerical model (the variable case). The model considers slip on a plane at a constant rate, and so does not account for dynamic frictional rupture scenario. We test a wide range of medium permeabilities of 10−22–10−16 m2 and porosities 0.5%–17%, based on experimental data for Frederick diabase, Westerly granite and the Hanaore Fault gouge. We find that the predicted shear stress drop and temperature rise is similar between the two cases for low permeability (&lt;10−20 m2) and low porosity (&lt;1%) fault rocks, owing to an increase in the fluid pressurization factor and hydraulic diffusivity. Differences between the two models are evident in more permeable and porous fault rocks. The increase in hydraulic diffusivity during TP results in a diffusional length which scales with time0.7 in the variable case. In addition, our calculations show that it is important to apply the constant case model with the ambient initial conditions for the modeled fault zone and not time‐averaged values that aim to represent the temperature and pressure changes that occur during TP.

An alternative to the fault-valve model

This paper proposes a mechanism called the mode-switching model that is presented as an alternative to the fault-valve model. This mechanism is relevant to open-flow, low-porosity, fluid-saturated systems deforming by pressure solution creep. As opposed to most constitutive models discussed in the geological literature, the yield envelope is capped at high normal stresses, as demonstrated by experimental studies. A low-permeability rock has relatively high pore fluid pressure for a given input fluid flux. This increases the dissolution rate for quartz that in turn leads to a higher-permeability rock, low fluid pressure for the same flux and decreased quartz solubility and deposition, returning to a low permeability. This cycle continues indefinitely so long as the rock mass is stressed, a fluid flux is applied, and pressure solution operates. The high fluid pressure drives the Mohr stress circle to the tensile end of the yield envelope resulting in crack-seal and extensional veins. The low fluid pressure drives the Mohr stress circle to the cap end of the yield envelope resulting in laminated veins in rocks undergoing mineral reactions with large net volume losses coupled with solute transfer. Failure at the cap end of the yield envelope results in displacement discontinuities inclined at high angles to σ 1. Previously, these orientations have been taken to represent reactivated normal faults, an integral component of the fault-valve process. In the model presented, the yield surface prohibits the system ever reaching super-lithostatic pressures. The process of effective stress-driven switching between tensile and cap ends of the yield envelope arises from competition between dissolution and deposition, and is independent of any seismic events, fault reactivation or the episodic breaching of an impermeable seal. It provides a unifying, self-consistent concept for the interpretation of joints, faults and veins in hydrothermal systems.

Characterization of Extra Low-Permeability Conglomerate Reservoir and Analysis of Three-Phase Seepage Law

The micro distribution of residual oil in low-permeability sandstone reservoirs is closely related to pore structure, and the differences in pore structure often determine the reservoir’s productivity and development effectiveness from a macro perspective. On the basis of in-depth research, this paper analyzes the distribution law of the remaining microscopic oil, establishes the digital core multi-stage pore network modeling of the strongly sorted heterogeneous conglomerate reservoir in the Lower Wuerhe Formation of Block 8 of the Karamay Oilfield, the three-phase seepage simulation method considering the release of dissolved gas, and the three-phase permeability curve test. The research results are as follows: (1) Conventional physical property analysis shows that the permeability of core samples exhibits an inverse rhythmic distribution with layer depth. (2) CT core analysis and mercury injection experiments indicate that the area with porosity ranging from 9% to 21% accounts for 79% and is the main seepage channel area. Larger pores play an important role in seepage. (3) Through comparative experiments on cores with different permeability, it was found that the degassing phenomenon of low-permeability rock samples is more severe. In the actual process of reservoir development, it is necessary to reasonably handle the impact of water injection on development effectiveness, select appropriate water injection methods and cycles, and avoid premature water breakthrough in ultra low-permeability reservoirs.

Is There a Viscoelastic Effect of Low-MW HPAM Polymers on Residual Oil Mobilization in Low-Permeability Rocks at a Darcy Velocity of 0.2 ft/Day?

Is There a Viscoelastic Effect of Low-MW HPAM Polymers on Residual Oil Mobilization in Low-Permeability Rocks at a Darcy Velocity of 0.2 ft/Day?

A novel method to estimate the Stress-Dependent Kozeny-Carman constant of Low-Permeability, clastic sedimentary rocks

The stress-dependent permeability of low-permeability sedimentary rocks has seized attention because of the growing need for fossil fuels, geological carbon sequestration, and radioactive waste disposal. The Kozeny-Carman equation (K-C equation) is a well-known model for predicting the permeability of sedimentary rocks. The Kozeny-Carman constant (K-C constant, ckc) in the K-C equation accounts for the shape of the pores and the complexity of the pore conduit geometry in rocks. The pore structure of rocks varies owing to compaction at different burial depths. Therefore, the ckc is stress-dependent, a key parameter for understanding the stress-dependent permeability of rocks. However, measuring the stress-dependent ckc in low-permeability rocks is challenging. The present study proposes a novel approach for measuring the stress-dependent ckc of low-permeability rocks. The key elements of the proposed approach are (1) utilizing the Klinkenberg slip factor to evaluate the pore structure of rocks under stress, and (2) measuring rock porosity and permeability simultaneously under stress. This study amended the existing apparatus to fulfill the aforementioned purpose. Silty sandstone and clayey siltstone were selected to illustrate the novel ckc measurement method. The measured ckc values were compatible with the measurement results of documented sandstones and mudstones (most stress-independent). Interestingly, the ckc increased with increasing effective confining stress but started to decrease when the applied stress exceeded a certain critical value. Finally, we provide a synthetic case demonstrating the importance of considering stress-dependent ckc for permeability prediction under stress. If we neglect the stress dependence of ckc, the prediction of permeability using the K-C equation can induce errors up to several orders of magnitude.

A quantitative approach for sealing capacity evaluation of caprock in candidate of aquifer gas storage.

The gas sealing capacity of caprock (SCC) is one of the key factors that determine whether aquifer trap can be constructed into underground gas storage (UGS). However, no standard protocol for evaluating SCC of candidate aquifers has been proposed. Based on the core observation, laboratory experiment, and well logging data, the sealing capacity of the target aquifer caprock of Permian mudstone in D5 block of Litan sag, China, is quantitatively evaluated. The important parameters of mineral brittleness, permeability, breakthrough pressure (BP), mechanical brittleness, thickness, and areal extent that affect the SCC are determined. The results of specific tests and data statistics show that the caprock of D5 block is a low permeability rock with a permeability of 10-4 mD, and the BP of undisturbed rock is greater than 38MPa. Although the brittle mineral quartz is abundant with an average of 38.38%, the mechanical brittleness is not strong under formation conditions. The direct caprock has a thickness of greater than 50m, and on the top of it is a high-quality indirect caprock that complements the physical closure. The results of a mathematical evaluation model show that except for the sealing index of sample 2, all the other samples have optimal sealing capacity. The field interference test shows that the optimal sealing capacity of the caprock meets the requirements of the construction of underground gas storage (UGS). The rationality of the comprehensive evaluation model can provide a reference for similar evaluation projects in the future.

Hydrostatic, strike-slip and normal stress true triaxial hydrofracturing testing of Blanco Mera Granite: breakdown pressure and tensile strength assessment

We have designed and built a versatile testing device to perform hydraulic fracturing experiments under true triaxial conditions. The device, based on a stiff biaxial frame that can be installed in a servocontrolled press, can accommodate cube rock samples of up to 150 mm-edge. Using a low-permeability rock known as Blanco Mera granite, we have performed a series of tests across a range of confining pressures including hydrostatic, normal, and strike-slip regimes. We have verified the applicability of two simple fracture mechanics-based models for the interpretation of experimental results, and we have determined the value of tensile strength of the rock from the injection curves recorded. The orientation of the hydraulically-triggered fractures with respect to the applied stress has also been analyzed. Although the models proposed by Rummel and Abou-Sayed provided reasonably satisfactory results, especially for hydrostatic and strike-slip tests, the presence of heterogeneities and defects in the rock matrix may have a strong influence on the fracture behavior and, therefore, affect the interpretation of hydrofracturing tests.