Fluid Distribution Patterns Research Articles

A petrophysically driven seismic inversion method for the total organic carbon content of source rocks

Organic carbon content is the main index for evaluating organic matter abundance of source rocks, and it is still difficult to quantitatively predict total organic carbon (TOC) in source rocks based on seismic data. The study of seismic fluid identification driven by petrophysics can help to understand the fluid characteristics and distribution patterns of subsurface oil and gas reservoirs. First, this paper clarifies the sweet spot parameters (parameters characterizing hydrocarbon enrichment) and sensitive elastic parameters (a parameter characterizing the nature of an ideal elastic body) of source rocks through theoretical petrophysical modeling. Next, the paper establishes the relationship between sensitive elastic parameters and sweet spot parameters TOC and constructs a statistical petrophysical model that can characterize the relationship between the two on this basis. And then we construct the joint distribution of TOC and elastic impedance through the Bayesian theoretical framework to obtain the maximum posterior probability estimate as the final TOC inversion results of source rocks. Our method successfully predicts the spreading of high-quality source rocks in the Wen4 Section of Lufeng 13 Subsag, and the inversion results are within an uncertainty range of ±14 m for well data, which proves the reliability of the method. The prediction results show that the organic matter abundance of source rocks in the Wen4 Section is high, and the organic carbon content is generally higher than 2%, which provides a reliable basis for the further implementation of the resource scale of the depression and the clarification of the hydrocarbon-rich area, which provides technical support for the evaluation of the source rocks of the new depression in the new area.

Influences of lithofacies on fluid mobility in mixed sedimentary rocks: Insights from NMR analysis of the middle Permian Lucaogou Formation, Junggar Basin

The multi-source mixed sedimentation resulted in a unique series of mixed fine-grained sedimentary rocks evolved within the Permian Lucaogou Formation in the Jimusar Sag, located in the southeastern Junggar Basin, China. The variety of lithofacies within this series resulted in pronounced heterogeneity of pore structures, complicating the analysis of fluid occurrence space and state within reservoirs. As a result, the impact of lithofacies on fluid mobility remains ambiguous. In this study, we employed qualitative methods, such as field emission scanning electron microscopy (FE-SEM) and thin section observation, and quantitative analyses, including X-ray diffraction (XRD), total organic carbon (TOC), vitrinite reflectance (Ro), high-pressure mercury intrusion (HPMI) porosimetry, and nuclear magnetic resonance (NMR), along with linear and grey correlation analyses. This approach helped delineate the effective pore characteristics and principal factors influencing movable fluids in the fine-grained mixed rocks of the Lucaogou Formation in the Jimusar Sag, Junggar Basin. The findings indicate the development of three fundamental lithologies within the Lucaogou Formation: fine sandstone, siltstone, and mudstone. Siltstones exhibit the highest movable fluid saturation (MFS), followed by fine sandstones and mudstones sequentially. Fluid mobility is predominantly governed by the content of brittle minerals, the sorting coefficient (Sc), effective pore connectivity (EPC), and the fractal dimension (D2). High content of brittle minerals favors the preservation of intergranular pores and the generation of microcracks, thus offering more occurrence space for movable fluids. A moderate Sc indicates the presence of larger connecting throats between pores, enhancing fluid mobility. Elevated EPC suggests more interconnected pore throat spaces, facilitating fluid movement. A higher D2 implies a more intricate effective pore structure, increasing the surface area of the rough pores and thereby impeding fluid mobility. Ultimately, this study developed a conceptual model that illustrates fluid distribution patterns across different reservoirs in the Lucaogou Formation, incorporating sedimentary contexts. This model also serves as a theoretical framework for assessing fluid mobility and devising engineering strategies for hydrocarbon exploitation in mixed fine-grained sedimentary rocks.

Impact of PAM-ZnO nanocomposite on oil recovery

A new nanocomposite (NC) comprising of ZnO nanoparticles and polyacrylamide (PAM) polymer hybrid agent is investigated for enhanced oil recovery in sandstone and carbonate rocks. A range of measurements are conducted to examine the behavior of NCs including NC synthesis and characterization, NC physical properties, stability analysis, IFT, and wettability as a function of NC concentration (from 100 to 1000 ppm). Furthermore, core flood tests are performed to evaluate oil recovery and relative permeability characteristics and a numerical model is established, and history matched.The zeta potential tests verified the stability of the set NC at 200 ppm concentration in water-based solutions, while a clear reduction in IFT from 29 mN/m to 5.5 mN/m was observed at the same NC concentration. A notable shift is observed in contact angle from 133° to 13° for the sandstone rock at a 1000 ppm NC concentration suggesting a significant shift in wettability from oil-wet to strongly water-wet after NC injection while the optimal contact angle for the sandstone occurred at NC concentration of 200 ppm. Furthermore, the flooding NCs resulted in a 16.05 % increase in oil recovery factor compared to seawater flood for sandstone while a 26 % increase was recorded for carbonate sample. Likewise, the mobility ratio after NC flooding compared to seawater flooding decreased from 8.56 to 1.46. We obtained a good history match of the water cut and oil recovery factor data by creating the core dimension model. In addition, according to the fluid distribution pattern (one of the simulator outputs), the fingering phenomenon was delayed after flooding the NC compared to seawater. This study provides new insights into the impact of nanocomposite on oil recovery enhancement in sandstone and carbonate formations.

Experimental investigation and simulation for hybrid of nanocomposite and surfactant as EOR process in carbonate oil reservoirs

Numerous studies have been presented in the literature on the effect of the combination of nanoparticles and surfactants on enhanced oil recovery (EOR). In this study, we investigated the synergistic effect of synthesized Nanocomposite (ZnO@PAM) and surfactant on enhanced oil recovery by performing zeta potential (evaluation of chemicals stability in the aqueous phase), adsorption, wettability alteration (evaluation of the quantitative and qualitative wetness), and interfacial tension testes. In addition, to better understand how the fluid moves after chemicals flood in the porous medium, the Cartesian model was developed in CMG-STARS. Besides, this model is valid because of the history match of the oil recovery data, water cut data, and relative permeability curves. The Nanocomposite was physically synthesized from polyacrylamide polymers and zinc oxide nanoparticles under reflux conditions. The CMC surfactant point was obtained by examining various parameters (pH, density, electrical conductivity, and IFT). In the next step, we prepared nano-surfactant solutions (Nanocomposites with different concentrations of 100 ppm, 200 ppm, 500 ppm, and 1000 ppm + Surfactant (CMC)). By investigating the results of the adsorption and zeta potential tests, it was observed that the combinations of Surfactant and NCs have a positive effect on each other (increased nanoparticle stability and decreased surfactant adsorption on the carbonate rock surface). The Surfactant and Nano-Surfactant reduced the IFT from 29.16 to 0.176 (mN/m) and 1.354 (mN/m), respectively. In addition, the Surfactant at CMC and Nano-Surfactant (Surfactant (CMC) + NCs (500 ppm)) improve the contact angle in carbonate rock from 145.86 to 64° and 12.79°, respectively. After the core flooding by Surfactant and hybrid of NCs and Surfactant, we saw an increase of 17.94% and 30% in oil recovery compared to seawater floods, respectively. Furthermore, we observed the effect of mobility control and reduction of the fingering phenomenon after the flooding of chemicals by analyzing the simulated fluid distribution. By constructing the model in the core dimensions, we were able to get a good history matching from the laboratory data. Moreover, the mobility ratio after simultaneous flooding of NCs and surfactant compared to seawater decreased from 13.354 to 1.86, respectively. In addition, according to the fluid distribution pattern (one of the simulator outputs) the fingering phenomenon, was delayed after flooding the hybrid of NCs and surfactant. The positive effect of this type of chemical compound on mobility control and the fingering phenomenon has caused increased oil recovery. This study's findings can help to understand better how hybrid chemicals perform on improved oil recovery.

Physiological Loading-Induced Interstitial Fluid Dynamics in Osteon of Osteogenesis Imperfecta Bone.

Osteogenesis imperfecta (OI), also known as "brittle bone disease," is a genetic bone disorder. OI bones experience frequent fractures. Surgical procedures are usually followed by clinicians in the management of OI. It has been observed physical activity is equally beneficial in reducing OI bone fractures in both children and adults as mechanical stimulation improves bone mass and strength. Loading-induced mechanical strain and interstitial fluid flow stimulate bone remodeling activities. Several studies have characterized strain environment in OI bones, whereas very few studies attempted to characterize the interstitial fluid flow. OI significantly affects bone micro-architecture. Thus, this study anticipates that canalicular fluid flow reduces in OI bone in comparison to the healthy bone in response to physiological loading due to altered poromechanical properties. This work attempts to understand the canalicular fluid distribution in single osteon models of OI and healthy bone. A poromechanical model of osteon is developed to compute pore-pressure and interstitial fluid flow as a function of gait loading pattern reported for OI and healthy subjects. Fluid distribution patterns are compared at different time-points of the stance phase of the gait cycle. It is observed that fluid flow significantly reduces in OI bone. Additionally, flow is more static than dynamic in OI osteon in comparison to healthy subjects. This work attempts to identify the plausible explanation behind the diminished mechanotransduction capability of OI bone. This work may further be extended for designing better biomechanical therapies to enhance the fluid flow in order to improve osteogenic activities in OI bone.

Distribution Model of Fluid Components and Quantitative Calculation of Movable Oil in Inter-Salt Shale Using 2D NMR

Some inter-salt shale reservoirs have high oil saturations but the soluble salts in their complex lithology pose considerable challenges to their production. Low-field nuclear magnetic resonance (NMR) has been widely used in evaluating physical properties, fluid characteristics, and fluid saturation of conventional oil and gas reservoirs as well as common shale reservoirs. However, the fluid distribution analysis and fluid saturation calculations in inter-salt shale based on NMR results have not been investigated because of existing technical difficulties. Herein, to explore the fluid distribution patterns and movable oil saturation of the inter-salt shale, a specific experimental scheme was designed which is based on the joint adaptation of multi-state saturation, multi-temperature heating, and NMR measurements. This novel approach was applied to the inter-salt shale core samples from the Qianjiang Sag of the Jianghan Basin in China. The experiments were conducted using two sets of inter-salt shale samples, namely cylindrical and powder samples. Additionally, by comparing the one-dimensional (1D) and two-dimensional (2D) NMR results of these samples in oil-saturated and octamethylcyclotetrasiloxane-saturated states, the distributions of free movable oil and water were obtained. Meanwhile, the distributions of the free residual oil, adsorbed oil, and kerogen in the samples were obtained by comparing the 2D NMR T1-T2 maps of the original samples with the sample heated to five different temperatures of 80, 200, 350, 450, and 600 °C. This research puts forward a 2D NMR identification graph for fluid components in the inter-salt shale reservoirs. Our experimental scheme effectively solves the problems of fluid composition distribution and movable oil saturation calculation in the study area, which is of notable importance for subsequent exploration and production practices.

In-situ investigation of wetting patterns in polymeric multibore membranes via magnetic resonance imaging

Wetting of the membrane to displace air or conditioning liquids is important to exploit the complex porosity of a filtration membrane. This study reveals the details of wetting in multibore membrane-based filtration modules. Using magnetic resonance imaging (MRI), we quantify the fluid distribution patterns during initial membrane wetting in dead-end permeation mode. The spatio-temporal evolution of aqueous copper sulfate solution wetting the membrane fibers was investigated as a function of the applied flux, packing density, and position along the membrane module length.Three initial wetting conditions were examined: delivery-state membranes, ethanol-washed and dried (air-filled) membranes, and ethanol-filled membranes. Significant changes in wetting patterns were observed due to interfacial and polymer swelling effects. This in-situ investigation reveals a slow wetting progression over six hours and more to obtain complete wetting, even at high fluxes of 200 LMH. However, an increased flux leads to faster wetting kinetics as the evolving wetting patterns are flux dependent. The packing density of the multibore fibers additionally impacts the wetting kinetics by shifting the prevalent pressure conditions. Although in dead-end mode, the wetting progression is non-uniform along the membrane module length.In addition to this parameter study, different pre-wetting agents’ effect on the displacement behavior was investigated in depth. This study helps to understand (a) complex wetting phenomena inside multibore membranes in dead-end filtration, (b) the membranes’ interaction with their surroundings due to neighboring membranes, and (c) the effect of the used fluid system for displacement on the resulting wetting patterns.

Numerical study on the impact of fluid distribution on a counter-current direct contact evaporator

Humidification-Dehumidification (HDH) desalination units have been extensively studied during the past decades using macro-scale modeling, which relies on empirical closure correlations. Nonetheless, the HDH process remains relatively inefficient in terms of total energy requirements when compared with other desalination technologies such as Reverse Osmosis (RO) or Multi-Stage Flash (MSF). To improve the performance of direct contact evaporation, modeling of the transport phenomena at the small local scale is required. The objective of the present paper is to accurately model the hydrodynamic as well as heat and mass transfer as it typically occurs in a HDH counter-current direct contact evaporator. The numerical model is based on the Volume-of-Fluid (VOF) method included in ANSYS Fluent v19.2, which is modified to properly model diffusion driven evaporation. The study with multiple fluid distribution patterns shows a high increase in liquid hold-up and evaporated mass with an increase in water spray density, while the gas distribution does not have a noticeable impact on the performance of the evaporator column. The insight provided by the CFD model highlights the importance of considering the water distributor in conjunction with the packed column design for improving the performance.

Thermal regime reconstruction and fluid inclusion LA–ICP–MS analysis on intermediate-sulfidation epithermal Pb–Zn veins: Implications for porphyry Cu deposits exploration in the Xianhualing District, Anhui, China

The Xianhualing District at Jinzhai in the northern Dabie Orogen, China, is a significant area for Pb–Zn–Cu–Au polymetallic exploration. The main rocks in the area are mica–quartz schist of the Neoproterozoic Foziling Group, and magmatic rocks which are controlled by two sets of faults striking NNE and NW. Recent drilling has revealed that the orebody occurs mainly in mica–quartz schist in the form of breccia and veinlets. Major ore minerals include pyrite, sphalerite, galena, chalcopyrite, magnetite, gold, silver, and silver sulfosalts, with alteration assemblages of predominantly quartz, sericite, calcite, and chlorite. Three types of fluid inclusions occur in quartz–sulfide vein samples collected from eight drill-holes: two-phase liquid-rich inclusions (type I), two-phase vapor-rich inclusions (type Ⅱ), and halite-bearing inclusions (type III). Microthermometric studies of type I and Ⅱ fluid inclusions indicate homogenization temperatures of 161–378 °C and salinities of 0.5–7.8 wt% NaCl equivalent. Fluid inclusion microthermometric data and mineralization and alteration characteristics indicate an intermediate-sulfidation epithermal environment. Current exploration is focused on the location of potential deep porphyry mineralization associated with epithermal mineralization. In this study, 28 drill-core samples from different levels were selected for fluid inclusion microthermometry to elucidate fluid-evolution pathways and hence to determine the likelihood of porphyry bodies. The consistent fluid inclusion petrography, distribution patterns, and fluid-evolution trends indicate that the deeper part of the Dongchong area may have been the regional thermal center of fluid flow. The estimated mineralization depths of type III fluid inclusions are in the range 0.4–1.5 km, indicating a relatively shallow formation. Fluid chemical compositions obtained from single-inclusion laser-ablation–inductively coupled plasma–mass spectrometry (LA–ICP–MS) analyses support the occurrence of a single magmatic–hydrothermal fluid source, which has a degree of mixing with meteoric water and a small amount of basinal brines during the migration path, and the fluid evolution pattern agrees well with the fluid inclusion mapping result. Quartz-vein hosted fluid inclusions contain significant amounts of Pb, Zn, and Cu, indicating good exploration prospects for porphyry Cu mineralization at depth.

Fluid distribution and gas adsorption behaviors in over-mature shales in southern China

To better understand the mechanism of hydrocarbon accumulation and fluid migration in Chinese shales, several samples from two leading marine shales (Longmaxi and Niutitang) were collected for geochemical and mineral analysis, the characterization of pore structure, preliminary studies on fluid flow, and the distribution and investigation of different methane adsorption behaviors. Firstly, the Longmaxi and Niutitang marine shales were found to be in an over-matured stage and dry gas window. Pore structures and connectivity were characterized by field emission - scanning electron microscopy (FE-SEM). The SEM images showed that the micro-fracture, interparticle pores, and organic pores had better connectivity than intraparticle pores. Results from contact angles indicated that the Longmaxi and Niutitang shales tended to have higher affinities for oil rather than for water. The connectivity of pores, distribution of fluids (water and gas) and fluid flow behaviors in the over-matured shale were analyzed using spontaneous imbibition (SI) and tracer diffusion tests. It was found the tracer fluids flow in the way of network flow inside of shale matrix. The connected pore network may be the main path for fluid migration in shale. Additionally, a gravimetric isothermal adsorption experiment was applied to assess methane adsorption capacity in shale. Shale samples with higher total organic carbon (TOC) contents had higher methane adsorption capacities. Organic matter (including kerogen and bitumen), had much greater adsorption capabilities than inorganic minerals (quartz, clay, and others). Finally, the fluid distribution patterns in over-matured marine shale were studied. Shale gas was originally generated in organic matter and then migrated out through connected pores, under differential pressure, between internal and external organic matter hydrocarbon generation areas. These hydrocarbons replaced the water in the pores. Therefore, shale gas may adsorb in organic pores and is freely stored in connected inorganic pores, with bound water, whereas isolated pores are saturated with water. Two different adsorption patterns on mineral surfaces (organic matters and inorganic minerals) were established to explain the different shale gas adsorption behaviors in organic pores and connected pores, with bound water.

Experimental study on the influence of saturation degree on unstable behavior within granular material

According to regulations and standards, risks of liquefaction are considered only if a soil is fully saturated. However, some authors have demonstrated that a soil can liquefy even with an initial degree of saturation under 100%. However, those studies remain descriptive and do not provide specific frameworks for evaluating the risk of liquefaction, taking the degree of saturation into account. This article presents an experimental study on the unstable behavior of sand as a function of its initial degree of saturation. Saturation states are defined and three saturation zones are investigated as a function of their pore fluid distribution patterns. Cyclic triaxial tests are performed on Fontainebleau sand to study the unstable behavior of each saturation zone. The results show that a soil can liquefy even if it is not initially fully saturated. They also provide new data on the role of suction and pore fluid compressibility in the unstable behavior of granular materials. The final aim of this article is to study the general unstable behavior of Fontainebleau sand under cyclic loading, and more specifically the influence of the degree of saturation on the triggering of these instabilities.

Determine Geothermal Fluid spreading pattern under subsurface using 2d Resistivity Imaging and geomagnetic method at Silaou Kahean

The Research has been carried out at geothermal Regional using 2d resistivity imaging and Gemagnetic method in Dusun Silou Kahean Subdistrict, Kabupaten Simalungun. The purpose of this study is to determine the distribution of earth magnetic anomalies, rock structures, and fluid distribution patterns. The measurement of geomagnetic method uses PPM (Proton Precession Magnetometer) type Elsec 770. Data retrieval have been done randomly with the number of points obtained by 40 measuring points, the data is processing by using surfer 10 to determine the contours and Mag2DC to obtain a magnetic anomaly cross section. The 2D resistivity imaging is used to determine the rock resistivity value. The results showed that the anomaly value with the geomagnetic method had the lowest value of 20.51 nT and the highest value of 67.18 nT. The susceptibility value of 0.00051 to 0,00098 cgs is indicated by sandstone and susceptibility value of 0.0013 to 0.0016 cgs is indicated by limestone. The 2D Resistivity imaging method has a resistivity value of 12.5 to 37.3 Ωm is indicated by Silts layer with a depth of 1.25-3.75 meters, and a resistivity value of 1.26 to 8.72 Ωm is indicated by c lay layer with a depth of 6.38-12.4 meters . from the results it can be concluded that the fluid dispersion contour using geomagnetic and geoelectric methods is spread across from the southwest to the northeast.

Fluid Distribution Pattern in Adult-Onset Congenital, Idiopathic, and Secondary Normal-Pressure Hydrocephalus: Implications for Clinical Care.

In spite of growing evidence of idiopathic normal-pressure hydrocephalus (NPH), a viewpoint about clinical care for idiopathic NPH is still controversial. A continuous divergence of viewpoints might be due to confusing classifications of idiopathic and adult-onset congenital NPH. To elucidate the classification of NPH, we propose that adult-onset congenital NPH should be explicitly distinguished from idiopathic and secondary NPH. On the basis of conventional CT scan or MRI, idiopathic NPH was defined as narrow sulci at the high convexity in concurrent with enlargement of the ventricles, basal cistern and Sylvian fissure, whereas adult-onset congenital NPH was defined as huge ventricles without high-convexity tightness. We compared clinical characteristics and cerebrospinal fluid distribution among 85 patients diagnosed with idiopathic NPH, 17 patients with secondary NPH, and 7 patients with adult-onset congenital NPH. All patients underwent 3-T MRI examinations and tap-tests. The volumes of ventricles and subarachnoid spaces were measured using a 3D workstation based on T2-weighted 3D sequences. The mean intracranial volume for the patients with adult-onset congenital NPH was almost 100 mL larger than the volumes for patients with idiopathic and secondary NPH. Compared with the patients with idiopathic or secondary NPH, patients with adult-onset congenital NPH exhibited larger ventricles but normal sized subarachnoid spaces. The mean volume ratio of the high-convexity subarachnoid space was significantly less in idiopathic NPH than in adult-onset congenital NPH, whereas the mean volume ratio of the basal cistern and Sylvian fissure in idiopathic NPH was >2 times larger than that in adult-onset congenital NPH. The symptoms of gait disturbance, cognitive impairment, and urinary incontinence in patients with adult-onset congenital NPH tended to progress more slowly compared to their progress in patients with idiopathic NPH. Cerebrospinal fluid distributions and disease progression were significantly different among the patients with adult-onset congenital NPH, idiopathic NPH and secondary NPH. This finding indicates that the pathogenesis of adult-onset congenital NPH may differ from those of idiopathic and secondary NPH. Therefore, adult-onset congenital NPH should be definitively distinguished from the categories of idiopathic and secondary NPH.

Distribution of Extracellular Fluid in Legs with Venous Edema and Lymphedema.

This study aimed to determine the specific fluid distribution pattern in legs with lymphedema (LE) in comparison to normal legs and legs with venous edema (VE) using bioelectrical impedance analysis (BIA). BIA was performed in 47 patients with lymphedema (LE; 63 legs), 33 patients with venous edema (VE; 60 legs), and 33 normal subjects (N; 66 legs). The ratio of intracellular fluid (ICF) resistance (Ri) to extracellular fluid (ECF) resistance (Re) of a whole leg normalized to the right arm (Ri/Re leg), a surrogate parameter for ECF/ICF, and the Ri/Re of the thigh and calf without normalization (Ri/Re thigh, Ri/Re calf, respectively) were obtained. Increases in Ri/Re leg (N 2.5 ± 0.7, VE 3.9 ± 3.7, LE 3.7 ± 1.5), Ri/Re thigh (N 1.8 ± 0.5, VE 3.2 ± 3.8, LE 3.8 ± 1.9), and Ri/Re calf (N 2.6 ± 0.6, VE 4.6 ± 1.7, LE 4.4 ± 2.2) were confirmed in VE and LE compared to normal subjects. However, the ratios of Ri/Re calf to Ri/Re thigh in normal subjects and those with untreated VE/LE were all ∼1.5 (N 1.5 ± 0.3, VE 1.5 ± 0.7, LE 1.6 ± 0.7). Fluid content was increased in legs with VE and LE compared to normal subjects, while the mode of gravitational fluid distribution was similar among all legs. Thus, no specific finding for LE was confirmed.

Investigating Darcy-scale assumptions by means of a multiphysics algorithm

Multiphysics (or hybrid) algorithms, which couple Darcy and pore-scale descriptions of flow through porous media in a single numerical framework, are usually employed to decrease the computational cost of full pore-scale simulations or to increase the accuracy of pure Darcy-scale simulations when a simple macroscopic description breaks down. Despite the massive increase in available computational power, the application of these techniques remains limited to core-size problems and upscaling remains crucial for practical large-scale applications. In this context, the Hybrid Multiscale Finite Volume (HMsFV) method, which constructs the macroscopic (Darcy-scale) problem directly by numerical averaging of pore-scale flow, offers not only a flexible framework to efficiently deal with multiphysics problems, but also a tool to investigate the assumptions used to derive macroscopic models and to better understand the relationship between pore-scale quantities and the corresponding macroscale variables. Indeed, by direct comparison of the multiphysics solution with a reference pore-scale simulation, we can assess the validity of the closure assumptions inherent to the multiphysics algorithm and infer the consequences for macroscopic models at the Darcy scale. We show that the definition of the scale ratio based on the geometric properties of the porous medium is well justified only for single-phase flow, whereas in case of unstable multiphase flow the nonlinear interplay between different forces creates complex fluid patterns characterized by new spatial scales, which emerge dynamically and weaken the scale-separation assumption. In general, the multiphysics solution proves very robust even when the characteristic size of the fluid-distribution patterns is comparable with the observation length, provided that all relevant physical processes affecting the fluid distribution are considered. This suggests that macroscopic constitutive relationships (e.g., the relative permeability) should account for the fact that they depend not only on the saturation but also on the actual characteristics of the fluid distribution.

Modulus defect, velocity dispersion and attenuation in partially-saturated reservoirs of Jurassic sandstone, Indus Basin, Pakistan

Partially saturated reservoirs are one of the major sources of seismic wave attenuation, modulus defect and velocity dispersion in real seismic data. The main attenuation and dispersion phenomenon is wave induced fluid flow due to the heterogeneity in pore fluids or porous rock. The identification of pore fluid type, saturation and distribution pattern within the pore space is of great significance as several seismic and petrophysical properties of porous rocks are largely affected by fluid type, saturation and fluid distribution pattern. Based on Gassmann-Wood and Gassmann- Hill rock physics models modulus defect, velocity dispersion and attenuation in Jurassic siliclastic partially-saturated rocks are studied. For this purpose two saturation patterns - uniform and patchy - are considered within the pore spaces in two frequency regimes i.e., lower frequency and higher frequency. The results reveal that at low enough frequency where saturation of liquid and gas is uniform, the seismic velocity and bulk modulus are lower than at higher frequency where saturation of fluid mixture is in the form of patches. The velocity dispersion and attenuation is also modeled at different levels of gas saturation. It is found that the maximum attenuation and velocity dispersion is at low gas saturation. Therefore, the dispersion and attenuation can provide a potential way to predict gas saturation and can be used as a property to differentiate low from high gas saturation.

Experimental evaluation of conductive flow imaging using magnetic induction tomography

Multi-phase flow imaging is a challenging topic in industrial process tomography. In this paper, we present a non-invasive imaging technique for the electrically conductive phase of a multi-phase flow problem. Magnetic induction tomography (MIT) is sensitive to the conductivity of the target, and as such has the potential to be used as an imaging technique to visualise the conductive components in a multi-phase flow application. A 16 channel MIT system is used for this study, among which eight excitation coils are supplied with a 15V peak, 13MHz sinusoidal signal in sequence from a signal generator, while the remaining eight coils are floated as receivers. The imaging region of this MIT system has an inner and outer diameter of 190mm and 200mm respectively. Static fluid distribution patterns are produced using several fluids with different conductivities and placed inside the imaging region to form conductivity phase contrasts. Experimental results show within our hardware and software capability, a conductivity contrast of 0.06S/m for an inclusion that occupies 8.69% of the imaging region can be imaged. An in-depth experimental evaluation of the system response towards various fluid measurements is shown for the first time, as are results for quasi-static fluid experiments showing that a non-homogenous flow of gas bubbles can be imaged in various conductive backgrounds. In sum, the analyses presented investigate the feasibility and capability of MIT for this application, while also reporting some of the first flow rig tests in this field.

Rock physics modeling to assess the impact of spatial distribution pattern of pore fluid and clay contents on acoustic signatures of partially-saturated reservoirs

The identification of pore fluid type, saturation and distribution pattern within the pore space is of great significance as several seismic and petrophysical properties of porous rocks vary largely by fluid type, saturation and fluid distribution pattern. With the help of rock physics modeling, the impact of fluid saturation as well as fluid distribution pattern on seismic velocities, acoustic impedances and seismic amplitudes is estimated on porous rock of early Cretaceous Mississauga sands. For this purpose two saturation patterns: uniform and patchy saturations are considered within the pore spaces. The primary goal of this study is to understand the vertical and horizontal trends of numerous seismic parameters such as P-wave velocity (V P ), S-wave velocity (V S ), their impedances, V P /V S ratio, bulk density (ρ b ), seismic reflectivity etc. as a function of fluid saturation, saturation pattern (patchy or homogeneous), porosity (ϕ) and clay content. The results reveal that the seismic parameters and offset dependent amplitudes are very sensitive to pore fluid saturation and distribution patterns and physical properties. As the hydrocarbons (oil/gas) saturation increases, the compressional wave velocity decreases. P-wave velocity is 20–40 % higher in case of patchy saturation than of homogeneous saturation. Similarly, reservoir porosity and clay matrix control the elastic response of porous rock due to which seismic velocities decrease with increase in porosity and clay content.

Intramuscular distribution of botulinum toxin—Visualized by MRI

ObjectiveA precise knowledge of the spread of botulinum toxin (BoNT) in muscle tissue is required to efficiently access endplate zones and increase BoNT's therapeutic efficacy. Here, we aimed to understand the spatiotemporal dynamics of BoNT distribution in skeletal muscle and its modulating factors, such as injected volume and exercise after injection. MethodsTo visualize distribution in muscle tissue, sagittal, dynamic, balanced fast field echo (BFFE) MRI imaging was performed during injection of 1ml BoNT/NaCl bolus in spastic biceps brachii muscles (SBB, n=4), and 1ml NaCl in the right and 2ml NaCl in the left healthy biceps brachii (HBB, n=6), with or without successive muscle exercise. The pattern of extracellular fluid distribution was evaluated by T2-weighted and diffusion tensor imaging (DTI) sequences. ResultsBFFE indicated an immediate increase in hyperintensity, parallel to the muscle fibers, in the shape of a long (5.3±1.7cm) and thin (0.52±1.3cm) layer in HBB. The layer in SBB was shorter (3.25±0.6cm, p=0.01) and tended to be thicker (0.74±2.9cm, p=0.27). In HBB, an increase in volume (2ml) resulted in an increase in thickness (0.95±0.2cm, p=0.015), but a consistent length (5.67±1.3cm, p=0.54). DTI visualized a change of diffusion, which exceeded the bolus region by approximately 0.5cm. Redistribution occurred 10min after injection and was more prominent in HBB, compared to SBB. Additional muscle activity did not alter the diffusion pattern or bolus distribution. ConclusionInjecting BoNT at different depths perpendicular to the direction of the muscle fiber might optimize the efficacy of BoNT treatment. Additional sites along muscle fibers should be considered in SBB.

BISQ model based on a Kelvin-Voigt viscoelastic frame in a partially saturated porous medium

Taking into account three important porous media mechanisms during wave propagation (the Biot-flow, squirt-flow, and solid-skeleton viscoelastic mechanisms), we introduce water saturation into the dynamic governing equations of wave propagation by analyzing the effective medium theory and then providing a viscoelastic Biot/squirt (BISQ) model which can analyze the wave propagation problems in a partially viscous pore fluid saturated porous media. In this model, the effects of pore fluid distribution patterns on the effective bulk modulus at different frequencies are considered. Then we derive the wave dynamic equations in the time-space domain. The phase velocity and the attenuation coefficient equations of the viscoelatic BISQ model in the frequency-wavenumber domain are deduced through a set of plane harmonic solution assumptions. Finally, by means of numerical simulations, we investigate the effects of water saturation, permeability, and frequency on compressional wave velocity and attenuation. Based on tight sandstone and carbonate experimental observed data, the compressional wave velocities of partially saturated reservoir rocks are calculated. The compressional wave velocity in carbonate reservoirs is more sensitive to gas saturation than in sandstone reservoirs.