The competitive adsorption of CO2 and CH4 on kerogen and clay surfaces significantly affects CO2 sequestration and enhanced gas recovery (EGR) in organic shale-gas reservoirs. Conventional laboratory methods struggle to quantify individual gas adsorption in CO2:CH4 mixtures. To address this challenge, we aim to quantify (a) the effects of kerogen type, pore structure, and thermal maturity on CO2:CH4 competitive adsorption, (b) the impact of clay surface chemistry on the adsorption capacity of organic shale formations, and (c) the influence of different moisture and oil contents on the adsorption capacity of kerogen and clay structures. We used Grand Canonical Monte Carlo (GCMC) simulations (verified against previously documented experimental measurements) to investigate how kerogen composition, pore structure, and thermal maturity, water/oil saturation, and clay surface chemistry influence CO2 adsorption under reservoir conditions. Results suggest that changing kerogen from type I to III increases CO2 adsorption from 1.42 mmol/g to 5.56 mmol/g at 330 K and 20 MPa. Increasing thermal maturity significantly affected CO2 adsorption, though raising reservoir pressure from 1 MPa to 20 MPa reduces CO2/CH4 selectivity. Moreover, the presence of moisture and oil decrease maximum CO2 adsorption. For clay minerals, the positively charged K-illite enhances CO2 adsorption by 133 % compared to negatively charged illite and exhibits a CO2/CH4 selectivity of 17.2 versus 1.48 in kaolinite. These findings emphasize that reservoir conditions as well as composition critically affect adsorption capacity and selectivity. The introduced molecular simulation framework enabled extensive sensitivity analyses of factors influencing CO2 storage at conditions that extend beyond the reach of conventional laboratory experiments, which potentially enables the optimization of CO2 storage strategies in organic shale-gas reservoirs.

Caprock sealing capacity is essential for carbon geological storage in saline aquifers and depleted oil and gas formations. Clay-rich caprocks and fault gouge are expected to hold buoyant CO2 in the storage formation by capillary forces. However, all direct capillary sealing capacity measurements of clay-rich rocks to CO2 were so far limited to pressures below similar to 20 MPa and/or temperatures below 50 degrees C, typically lower than target storage conditions. This paper presents new results of brine absolute permeability, capillary CO2 breakthrough pressure, and post-breakthrough CO2 permeability for resedimented kaolinite clay plugs at fluid pressures greater than 41 MPa, temperatures of 60 degrees C and 80 degrees C, and mean effective stress of similar to 6.8 MPa. The results show that breakthrough pressure (P-CO2 - P-w) is always positive and remains in the interval between similar to 1.4 MPa and 2.8 MPa within the range of pressure and temperature explored. Moreover, average post-breakthrough CO2 relative permeability is similar to 5 %. An additional test with a clay mixture representative of a shale from the North Sea, at similar pressure-temperature conditions held a differential pressure, i.e., no breakthrough, over three months with a maximum difference P-CO2 - P-w = 5.71 MPa. Results and analysis support the water-wet properties of clays at high pressure and temperature and the resulting capillary sealing capacity to CO2. These results support expectations that clay-rich caprocks are satisfactory seals for holding buoyant CO2 via capillary forces. Results also suggest that if the sealing capacity is surpassed, clay-rich caprocks can limit advective flow because of their low CO2 relative permeability and potential for resealing through snap-off.

We investigate the impact of fractures on the effective thermomechanical response of porous media using numerical simulation. While dual porosity is a popular numerical model for multiphase flow effective models, research on the macroscale hydro-thermo-mechanical response in the presence of fractures is scarce. This work uses an in-house numerical framework with automated mesh generation, fracture distribution, simulation, and postprocessing for the investigation. The proposed model explores the following effective parameters: drained bulk modulus, drained Poisson ratio, drained Biot coefficient, Skempton B coefficient and drained thermal expansion coefficient. Results indicate that the fracture network is impactful even considering low fracture densities and that using results from laboratory experiments conducted in intact samples may mislead large-scale field interpretations of fractured media. Disregarding the fractures, results in overestimating the effective Biot coefficient and Skempton coefficient B, underestimating the effective drained Bulk Modulus; and overestimating the drained thermal expansion coefficient. Altogether, the macroscopic impact of the fractures is an important strain absorption mechanism for matrix stresses that can be effectively upscaled into field-scale models. Using parameters of a naturally fractured carbonate reservoir, we provide an example where a matrix-based geomechanical model may lead to erroneous interpretations of fracture propagation within the reservoir. Conversely, the effective medium parameters model leads to a smaller stress contrast between the reservoir and the caprock.

Jurassic reservoir-caprock sequences in Saudi Arabia play a critical role in both hydrocarbon systems and future CO2 storage, where long-term structural trapping relies on the hydraulic and mechanical integrity of the caprock. This work provides a mechanical characterization of these sequences, including the Manifa, Hith, and Arab A, B, and C formations. This paper focuses on a 210-meter continuous near outcrop core section from the Jurassic Sulay, Hith, and Arab formations in Saudi Arabia, marking the first published comprehensive and continuous petrophysical and rock mechanical analyses of this sequence. A series of laboratory measurements including scratch and ultrasonic tests as well as triaxial loading tests were conducted to evaluate petrophysical properties, assess mechanical stratigraphy, and determine brittle-ductile transition with a particular focus on the evaporite (anhydrite) layers, the seals. Additionally, facies and geochemical analyses were conducted to link depositional environments and mineral composition with mechanical properties. The results reveal significant variation in strength and stiffness across the formations, with a strong correlation between mechanical stratigraphy and facies. The brittle-ductile transition mapped within the core presents critical implications for the caprock hydro-mechanical integrity during CO2 injection. Ultimately, these findings offer key insights into the mechanical behavior of evaporitic seals and strategies for safe CO2 injection and permanent storage.

Injection of carbon dioxide (CO2) at temperature lower than the target geological formation alters the reservoir-caprock stresses due to both pressure and temperature changes. The stresses evolve spatially and temporally during long-term injection. Predicting such stress changes is crucial to ensure mechanical integrity of sealing caprock. We implement a robust coupled thermal-hydro-mechanical (THM) formulation based on Cheng's thermo-poroelasticity into a commercial finite difference solver and adopt a 2D axisymmetric model for injection via a single vertical well. This study explores long-term cold CO2 injection (ΔT = -30°C) with special emphasis on exploring the role of caprock permeability on varying drainage responses. Numerical results show that stress redistribution caused by THM response leads to variations in the minimum total horizontal stress (i.e., fracture gradient in normal faulting stress regime) that depend on the extent of the cooling front. In general, total horizontal stresses decrease within the cooling front and increase above the cooling front. Pore pressure in the caprock may reduce significantly as caprock response tends to undrained conditions for ~nanodarcy caprock permeability. The simulations help predict stress changes and dynamic fracture gradients including the effects of temperature for safe and massive geological carbon storage.

The efficacy of geological carbon sequestration is reliant on the integrity of the caprock and its resistance to physical and chemical alteration. Caprocks with high abundance of reactive carbonates like calcite are susceptible to acid-promoted dissolution and can result in structural weakening. This work investigates the effect of acidified brine flow through an artificially fractured, high-carbonate (30 % by XRD) shale under differential compressive stress. Cylindrical samples were cut in half vertically and milled to create an artificial fracture with interlocking asperities and open channels. Samples were sheared with a single applied stress in a custom flow cell housed within an industrial CT scanner. Either acidic (pH 4) or reservoir-simulated (pH 9.5) brine was flowed through the artificial fracture for 7–8 days under reservoir pressure and room temperature. Model simulations indicate flow mainly occurred in open channels, with limited flow between overlapping asperities. Analysis of fracture surfaces by optical and scanning electron microscopy show increased surface alteration and roughness after exposure to pH 4 versus pH 9.5 brine indicating mineral dissolution/loss, and this effect is greater in areas that receive the highest brine flows. Similarly, surface analysis by scratch testing shows fracture toughness decreases more after exposure to acidic versus reservoir-simulated brine, with the greatest alteration in areas of highest acidic brine flows. Despite weakening, no shear slip occurred. Overall, the results indicate that acidified brine can result in significant physical and geomechanical alteration of irregular fracture surfaces in shale caprock, with greatest effects in preferential flow regions.

An uncommon facet of formation evaluation is the assessment of flow- related in - situ properties of rocks. Most of the models used to describe two - phase flow properties of porous rocks assume homogeneous and/or isotropic media, which is hardly the case with actual reservoir rocks, regardless of scale; carbonates and grain- laminated sandstones are but two common examples of this situation. The degree of spatial complexity of rocks and its effect on the mobility of hydrocarbons are of paramount importance for the description of multiphase fluid flow in most contemporary reservoirs. There is thus a need for experimental and numerical methods that integrate all salient details about fluid - fluid and rock - fluid interactions. Such hybrid, laboratory- simulation projects are necessary to develop realistic models of fractional flow in complex rocks, i.e., saturation- dependent capillary pressure and relative permeability. Furthermore, these two crucial properties are usually measured independently. Capillary pressure is typically assessed using static measurements and unrealistic pressure conditions, whereas relative permeability is evaluated dynamically. Consequently, the disparity between the nature of the two experimental procedures often results in a potentially significant loss of information. We document a new high- resolution visualization technique that provides experimental insight to quantify fluid saturation patterns in heterogeneous rocks which allow for the simultaneous and dynamic evaluation of two - phase flow properties. The experimental apparatus consists of an X - ray microfocus scanner and an automated syringe pump. Rather than using traditional cylindrical cores, thin rectangular rock samples are examined, their thickness being one order of magnitude smaller than the remaining two dimensions. During the experiment, the core is scanned quasicontinuously while the fluids are being injected, allowing for time - lapse visualization of the flood front. Numerical simulations are then conducted to match the experimental data and quantify effective saturation- dependent relative permeability and capillary pressure. The experimental results indicate that flow patterns and in - situ saturations are highly dependent on the nature of the heterogeneity and bedding - plane orientation during both imbibition and drainage cycles. In homogeneous rocks, fluid displacement approaches pistonlike behavior. The assessment of capillary pressure and relative permeability is performed by examining the time - lapse water saturation profiles resulting from fluid displacement. In spatially complex rocks, high- resolution time - lapse images reveal preferential flow paths along high- permeability sections and a lowered sweep efficiency. Our experimental procedure emphasizes that capillary pressure and transmissibility differences play an important role in fluid- saturation distribution and sweep efficiency at late times. The method is fast and reliable to assess mixing laws for fluid- transport properties of rocks in spatially complex formations.

ABSTRACT: The long-term success of an Enhanced Geothermal System (EGS) project requires distributed fluid flow in created fractures, ideally each with uniform and moderate permeability to avoid early thermal breakthrough. Yet, thermal depletion causes fracture opening, increasing the likelihood of flow channeling in areas with high fracture permeability. Furthermore, the effective reservoir rock stiffness (including natural fracture compliance) has a first-order impact on thermally induced stress changes, and thus fracture permeability. The objective of this work is to explore the role of thermal depletion on hydraulic fracture permeability considering a non-linear elastoplastic geothermal reservoir response. We utilize three-dimensional numerical simulations based on effective medium theory of fractured rocks to implicitly account for natural fracture compressibility and strength. Results demonstrate that a portion of the thermal strain-induced by cooling- is absorbed by natural fracture compressibility, which reduces the overall stress change, and tends to attenuate hydraulic fracture opening. Critically stressed natural fractures can yield during operation and decrease the likelihood of flow channeling. Lastly, the modeling results indicate that linear elastic models tend to overpredict fracture opening compared to models that account for effective properties of fractured rock masses. 1 INTRODUCTION Predictions of recoverable heat energy from Enhanced Geothermal Systems (EGS) reservoirs with models that neglect stress-dependent and non-linear fracture permeability are conservative estimates (Kohl et al., 1995). Flow channeling and thermal short-circuiting caused by thermo-poroelastic coupled feedback is often observed early on in field tests and would limit the installed capacity unless efforts were made to improve the flow distribution (MIT, 2006). Localized fracture opening increases injectivity and decreases the geothermal effective reservoir volume by localizing injected flow (Hicks et al., 1996). Hence, reservoir stresses (in-situ and any changes during operation) play a significant role in the distribution of EGS circulation fluid and evolution of fracture permeability (McLean and Espinoza, 2023). Spatial heterogeneity in the initial fracture aperture may further decrease reservoir performance from the beginning because preferential flow paths may exist prior to injection (Guo et al., 2016).

Deep closed-loop geothermal systems are a potential technology to provide heating and power generation. Although these systems are not new, they have recently regained interest because the design avoids reservoir stimulation (and potential fluid injection induced seismicity) and thermal short-circuiting of the working fluid. However, the poromechanical response to long-term heat depletion of closed-loop wells at large depths is largely unexplored. This paper investigates the response of rock around closed-loop geothermal system over 30-years of heat depletion through numerical simulation. The numerical solution is based on the theory of thermo-poroelastoplasticity and is solved through the Fenicsx finite element computing platform. The formulation takes effective poroelastoplastic properties of the bulk rock mass to indirectly account for strength and permeability of a rock mass with pre-existing fractures. Results for a normal faulting scenario show that the reservoir response to heat depletion causes vertical and horizontal stress redistribution far around the wellbores. Moreover, the rock mass may respond with partially undrained behavior in deep locations with a sparse fracture network. Shear failure may occur within a fraction -up to 30

ABSTRACT: Predicting the appropriate mud density in drilling operations is crucial in the construction of oil and gas wells, in order to mitigate the drilling problems and improve the drilling efficiency. This paper investigates ten failure criteria in directional wells drilled through different rock formations in the southern Iraq region. These rock formations experience sever drilling problems and colossal nonproductive time likely due to inappropriate selection of the mud densities with respect to directional drilling parameters. The geomechanical model proposed in this work was constructed from the available leak-off tests data, core analysis, and wireline geophysical logs. We calculated optimal mud densities from field data and show that the drilling densities in the field were inapropriate in many cases with respect to well inclination and azimuth. The Mogi Coulomb, Circumscribed Drucker-Prager, Modified Lade, and Modified Wiebols-Cook criteria predict optimal mud densities that are close enough to field observations. Also, we conducted a statistical analysis of the field data and core data and propose a new criterion to improve the prediction accuracy for shale rocks. This approach can be used as guideline to robust estimation of the mud windows in these problematic rock formations 1. INTRODUCTION Despite modern technologies in the gas and oil industry, wellbore instability is the most crucial challenge in terms of cost and time to complete the wells. Every year, drilling operations cost more than eight million dollars due to wellbore instability problems (Peng & Zhang, 2007), which wastes 10 percent of the wells budget (Aadnoy & Ong, 2003). Therefore, the main stages of well planning depend on wellbore stability (Bell & Gough, 1979). Thus, to avoid wellbore collapses, the mud weight should be equivalent to control the stress concentration, and the drilling direction should be according to the direction of the stresses. The drilling mud pressure provides wellbore stability when the mud pressure is within the limits of shear failure and fracture gradients (Bourgoyne, Millheim, Chenevert, & Young, 1986). Far-field stresses exist inherently in the earth, which will be changed due to drilling operations when replacing the mud weight instead of the drilled rocks. In contrast, borehole stresses occur on the wall that can be controlled using drilling mud weight. The wellbore stability model necessitates the inclusion of rock strength properties that govern how the rock behaves under in-situ stresses. A rock failure criterion defines the stress conditions leading to failure. Thus, to ascertain wellbore failure stresses, it is essential to determine the rock strength, select an appropriate constitutive model, and choose a precise rock failure criterion. The prevalent method for examining mechanical wellbore failure is through linear-poroelastic modeling. For the secure construction of wells, in-situ stresses must be leveraged to predict the minimum mud weight required to prevent wellbore wall breakouts. Several models have been developed to estimate the optimal mud density required to avert shear or tensile failure, aiming to ensure drilling operations are both safe and cost-efficient. Nevertheless, certain models may not accurately predict the necessary mud density, leading to significant non-productive drilling time or, in the worst-case scenario, the loss of the well, necessitating a sidetrack operation.

Several coal seams are contained within the formations of Great Artesian Basin (GAB), the largest natural underground water reservoir in Australia and the world. The extraction of coal seam gas (CSG) and its associated water from thousands of wells within the coal measures of the GAB has led to tens of millimetres of subsidence in CSG development areas. Since highly developed farming systems located in these areas rely on very low slope landforms, even this scale of subsidence has caused significant community concern about the potential for CSG extraction to impair farming operations and productivity through changes in land slope and drainage. Coal seam compaction associated with dewatering and gas extraction has two key components: poromechanical compaction and desorption -induced bulk shrinkage. The former results from pore pressure depletion (due to dewatering and gas extraction) and an increase of vertical effective stress, while the latter is induced by gas desorption from the coal matrix, leading to further deformation. While poromechanical compaction of fluid -bearing formations has been extensively addressed in the literature, relatively little research has been conducted on the role of coal shrinkage in CSG-induced subsidence. This paper introduces an innovative practical modelling approach for assessing CSG-induced subsidence at a subregional/regional scale. The approach utilises an analytical model for CSG-induced subsidence derived from constitutive stress - strain relations for poroelastic-sorptive media. This is a novel approach in the context of CSG-induced subsidence which considers both poromechanical compaction and desorption -induced shrinkage. A further distinction to previous work is the integration of the geomechanicalsorptive subsidence model with a numerical groundwater model. Based on this approach, this paper examines the effect of coal shrinkage on subsidence, and its proportions with respect to total compaction for one of the major coal measures in the Surat Basin. Input data are derived from three-dimensional geological, geomechanical, and groundwater models, as well as methane adsorption and desorption reports. Results show that (a) the impact of coal shrinkage on CSG-induced subsidence is likely to be significant in the study area and (b) the contribution of coal shrinkage to CSG-induced subsidence depends on gas content, Langmuir isotherm, shrinkage strain parameters, and the saturation state of coal. This study provides important insights into CSG-induced subsidence and lays the foundation for the development of robust, efficient, and localised predictive models to support environmental impact assessment and management.

Controlling the distribution of working fluid in an Enhanced Geothermal System (EGS) is crucial to prevent early thermal breakthrough and sustain the initial heat drainage area. Over time, working fluid flow may localize to a small area if fracture permeability increases non-uniformly, and efforts are not made to control the flow distribution. This scenario can potentially lead to mechanical reopening of hydraulic fractures, flow channeling, and thermal short-circuiting. However, current models neglect the nonlinear and inelastic deformation of fractured rock masses on EGS coupled thermo-mechanical response. The objective of this work is to estimate and predict the likelihood of thermal short-circuiting by flow-channeling in an EGS reservoir composed of rock and compliant natural fractures. We utilize three dimensional numerical solutions with reservoir properties based on effective medium theory of fractured rocks to achieve this objective. The results show that presence of natural fractures considerably changes the EGS response to thermal destressing, compared to linear poroelastic models. Flow channeling and short-circuiting, resulting in early thermal breakthrough, are more likely to occur in sparsely fractured reservoirs with stiff and strong natural fractures. Conversely, short-circuiting is unlikely in densely fractured reservoirs where thermal strains are absorbed by natural fracture opening and shear sliding rather than by rock matrix contraction. Estimation of natural fracture density is crucial in long-term forecasting and prediction of EGS power output. Accurate fracture characterization could decisively impact the fate of a project.

Structural trapping provided by seals is one of the key components of CO2 geological storage systems. Clay-rich caprocks and fault gouge are expected to be water-wet at supercritical CO2 conditions and to create a positive capillary pressure P-CO2-P-w > 0 MPa to ensure trapping of buoyant CO2. This paper presents the results of water imbibition experiments in resedimented clay mudrocks immersed in supercritical CO2 at temperature T >= 60 degrees C and pressure P-CO2 >= 25 MPa. The samples used in this work include kaolinite clay and Anahuac shale from the Gulf of Mexico Coast. Additional validation tests include Berea sandstone and silane-treated Berea sandstone. The results show spontaneous and rapid imbibition of water droplets into resedimented and rock samples initially saturated with wet supercritical CO2 for all cases. This outcome provides indirect evidence that typical siliciclastic caprock building minerals remain water-wet to CO2 at typical storage pressure and temperature conditions. The results and analysis indicate that siliciclastic caprock and fault gouge are expected to develop a positive capillary entry and breakthrough pressure to hold buoyant CO2 by capillary forces. These results validate expectations of buoyant CO2 structural trapping and field observations from natural analogues.

ABSTRACT: Accurate assessment and prediction of the in-situ horizontal stress is essential for ensuring the integrity of subsurface storage systems. Fluid injection and extraction affect the in-situ stresses. Changes of effective vertical stress are well constrained. However, changes of effective horizontal stress are not well characterized, particularly in the caprock where undrained loading and locked-in stresses can change the response significantly from drained linear poroelasticity predictions. In this study, we introduce a high-stress experimental setup designed to accurately measure horizontal stress during the consolidation process and subsequent unloading of clay-rich resedimented samples. Horizontal stress is determined by accurately measuring the tangential strain around the oedometer cell, while ensuring that this lateral strain is minimal enough to justify uniaxial strain condition. The results indicate that the K0 (ratio of horizontal to vertical effective stress) values converge to a constant value during loading (normally consolidated) as expected, but the unloading phase (over consolidated) presents a significant increase of K0 up to ∼2, increasing under undrained conditions. These results help calibrate advanced constitutive models to predict in-situ and change of effective vertical stresses in subsurface systems subjected to thermos-hydro-mechanical loadings. 1. INTRODUCTION Geo-energy projects, such as geologic carbon storage, hydrogen storage, and geothermal energy, alter the in-situ stress state by fluid injection or extraction. While the vertical stress is mostly affected by the overburden and can be calculated from depth and mass density, predicting horizontal stress requires an accurate constitutive model and knowledge of the loading history. In the case of mudrocks, characterizing the horizontal stress requires knowledge of the stress history, pore pressure and mineral composition (Casey et al. 2016). Mudrocks serve as sealing layers in many subsurface storage systems. Thus, properly assessing the horizontal stress is essential to ensure seal mechanical integrity (Guiltinan et al. 2018, Kim and Makhnenko 2020, Zheng et al. 2022). The coefficient of earth pressure at rest K0 is defined as the ratio between the horizontal and vertical effective stresses. (equation) Assuming zero lateral strain εlat = 0 is often referred to as the "K0-condition". K0 can be expressed as a function of the Poisson's ratio ν, where K0 = ν/(1-ν), under the assumption of linear isotropic poroelasticity. However, geomaterials including mudrocks generally exhibit responses that deviate siginificantly from this simplification (Prioul et al. 2004). Previous studies have developed empirical relationships from field experiments to estimate the K0 values, employing mini-frac or leak-off tests, and finding the relationship with overburden stress gradient (Brudy et al. 1997, Haimson and Chang 2002). However, fracture measurements are usually spare and difficult to obtain. Most importantly, field experiments do not capture the stress history or permit predicting changes, which is a critical factor for the evolution of horizontal stresses in mudrocks.

Coupled thermo-hydro-mechanical (THM) processes are ubiquitous in subsurface energy production and geological utilization and storage operations. Numerical simulation of strongly coupled THM processes is a non-trivial task, yet required to predict the performance of many applications in energy geomechanics. The majority of existing and open THM numerical codes are not user adaptable and do not include elastoplasticity coupled to mass and energy balance equations. This article presents an open source thermo-poroelastoplastic finite element numerical code with a fully-coupled monolithic solution strategy that is solved with Fenicsx computing platform. The formulation employs a mixed finite element scheme for pore pressure diffusivity equation, mean stress dependent yield surface, and non-associative plastic potential. The numerical solution is verified with small-scale conventional triaxial tests including drained and undrained compression and extension. We present example simulations reaching the yield surface induced by coupled hydromechanical and thermal loads. In addition, we present two example large-scale applications related to geothermal energy and carbon geological storage. Results show that the numerical solution accurately predicts changes of temperature, pore pressure, and stress for a wide range of model geometries and boundary conditions, including the plastic response. The code is freely available to the general community for use and modification.

Stress barriers play a key role in the propagation of hydraulic fractures. They are local maxima in the stress field that constrain vertical fracture propagation. The development of stress barriers is influenced by rock mechanical properties, pore pressure and tectonic stresses. However, stress prediction models are highly sensitive to available geophysical measurements and assumptions made on rock constitutive models. We compare stress estimations performed with elastic isotropic, anisotropic and viscoplastic models using Thomsen's notation (epsilon, delta, gamma) to quantify anisotropy and its effects on hydraulic fracture geometry. Using a single depth for principal stress calibration, we compare stress distributions and simulate hydraulic fracture geometries along simple vertical and horizontal well sections. Prediction errors stemming from isotropic models along anisotropic intervals increase when tectonic stresses increase. Errors generated by either over- or underestimation of d increase for tectonically passive environments, while errors generated by either over- or underestimation of. increase for tectonically active environments. Additional corrections, but also uncertainties, can be introduced by considering viscoelastic rock behaviour. Because of stress shadowing and fracture interaction, the risk of stress barrier underestimation is higher when estimating hydraulic fracture geometries along the various stages of horizontal wells.

Depletion zones are the least well understood component of mud volcanic systems. They are generally difficult to image using reflection seismic data, and have only rarely been identified and described in the subsurface. This study documents 277 mapped depletion zones in the western Nile Cone, offshore Egypt, of which the dimensions and stratigraphic characteristics of a sub-set of 86 depletion zones associated with mud volcanoes of early Pliocene to Recent age are recorded. The primary database used is a large (4,300 km2) 3D seismic survey in which depletion zones can be confidently interpreted using a set of simple criteria. The sub-set of 86 depletion zones were selected for morphometric analysis by virtue of the quality of seismic imaging. The depletion zones are characterised by circular to elliptical planforms with a bowl or conical geometry. They exhibit truncational stratal relationships with their parent stratigraphic unit, which in this area is the Mid-Late Miocene aged OM2 unit, and which occurs directly beneath the Messinian Evaporites. This geometry implies a top-down formation mechanism. Their diameters and relief range from is 600 m-3300 m, and 100 m-740 m, respectively, with a modest scaling relationship between diameter and relief. Flank angles of bowls and cones range from 11 & DEG; to 41 & DEG;, with a crudely normal distribution, with median and mean values of 26 & DEG;. A model for the evolution of depletion zones in the study area is based on two previous models developed for single source layer plumbing systems and invokes mobilisation of the source layer by sediment collapse and shear-induced liquefaction following initial seal failure by hydraulic fracturing of the evaporite seal. This mechanism may be more widely applicable to mud volcano systems than currently appreciated.

Accurate description and modeling of multiphase fluid flow are of paramount importance for subsurface resource engineering. The main source of information to quantify in-situ rock properties are borehole geophysical measurements, which are very often riddled with uncertainty ensuing from rock heterogeneity/ anisotropy and mud-filtrate invasion effects. Therefore, experimental methods are needed to accurately describe and quantify the physics of mud-filtrate invasion and mudcake deposition and its effects on borehole geophysical measurements. We developed a new high-resolution (10 to 50 & mu;m) experimental method to investigate the invasion of water-and oil-based drilling muds into rectangular rock samples using X-ray radiography. During mud injection, rock samples are scanned using high-resolution X-ray radiography, enabling the time-lapse visualization of both mud-filtrate invasion and external/internal mudcake deposition. Our experimental method successfully examines the effects of rock heterogeneity, bedding plane orientation, and anisotropy on the spatial distribution of fluids and mudcake formation resulting from mud-filtrate invasion. It also emphasizes the importance of mud properties on the final fluid saturation state once mudcake seals the borehole. The procedure is fast, accurate, and reliable to quantify the process of mud-filtrate invasion at the core scale, enabling an improved understanding of invasion effects on borehole geophysical measurements following drilling operations, especially in spatially complex rocks such as laminated sandstones and carbonates.

Borehole measurements, such as electrical resistivity, neutron porosity, or nuclear magnetic resonance, are critical for the in-situ petrophysical assessment of subsurface rocks. However, the interpretation of borehole measurements is often subject to uncertainty arising from their sensitivity to the interplay between mud filtrate, connate fluids, and the rock’s pore structure. This uncertainty remains present even in homogeneous geological formations. Mudcake deposition on the borehole wall causes additional complexity, impacting both well construction and formation evaluation. It is, therefore, essential to account for the latter effects and perform appropriate corrections when interpreting borehole measurements. Recently, new experimental procedures were introduced to quantitatively describe the process of mud invasion under realistic rock and fluid conditions, focusing on gas-bearing rocks and without considering how original saturating fluids affected the process of invasion. Both mud-filtrate invasion and filter-cake deposition must be understood and incorporated into numerical and analytical models to reliably interpret borehole measurements and maximize value. This objective can only be fulfilled via experiments. We use X-ray microfocus radiography to examine in real time the processes of mud-filtrate invasion and internal and external mudcake deposition in thin rectangular rock samples. The high-resolution experimental procedure (10 to 30 μm) mimics the borehole and near-wellbore regions and facilitates the time-lapse visualization of in-situ fluid-transport processes in spatially complex rocks. Water- and oil-based muds were injected into rock samples initially saturated with a range of different connate fluids, including viscous liquids, while being continuously scanned with X-rays. Because the injected drilling muds were the same across all experiments, the observed discrepancies between experiments originate from differences in rock properties, heterogeneity and anisotropy, or initial fluid saturation conditions. Experimental results emphasize the effect of rock heterogeneity and initial connate fluid on the spatial distribution of fluids and mudcake formation ensuing from mud-filtrate invasion. Mud-filtrate invasion rates and final average mudcake thicknesses were similar across all cases for a given drilling mud, suggesting that mudcake properties, as opposed to rock properties, were the controlling factors. By contrast, the spatial distribution of fluids in each rock sample varied significantly between cases, highlighting the impact of rock heterogeneity/anisotropy on the process of invasion. Laboratory experiments also emphasize the impact of viscous and/or capillary forces on mud-filtrate flow behavior. The experimental method is efficient and reliable, allowing for a better understanding of the uncertainty of the effects of mud-filtrate invasion on borehole geophysical measurements acquired while or after drilling.

Summary Polymer flooding is an enhanced oil recovery (EOR) method which improves the mobility ratio and sweep efficiency of a waterflood. In theory, the high viscosity of the polymer reduces its injectivity compared to water. However, field studies have documented much higher polymer injectivity than predicted by theoretical models. There are various reasons for high polymer injectivity. The objective of this work is to predict polymer injectivity in granular media accounting for fluid-induced fractures, water quality, polymer rheology, and undissolved polymers. We perform grain-scale, coupled fluid dynamics and granular mechanics modeling. Fluid-particle interactions are modeled by coupling computational fluid dynamics (CFD) and the discrete element method (DEM). Simulation results show that polymer injection can create fractures in the granular media along the direction perpendicular to the minimum principal stress, thereby reducing wellbore pressure buildup at a constant polymer injection rate. The polymer tends to flow in the direction of fracture propagation in granular media, so the direction of the fracture affects the swept area of the polymer. Polymer rheology, water quality, and undissolved polymer also affect the polymer injectivity. Suspended solid particles may plug pores and reduce the injectivity of polymer by ~25%. Mechanically trapped undissolved polymers can greatly reduce polymer injectivity in low-permeability granular media. This work shows for the first time initiation of polymer-driven fractures in a granular model and demonstrates its implications on polymer injectivity.