Fluids as primary carriers of sulphur and copper in magmatic assimilation

Magmas readily react with their wall-rocks forming metamorphic contact aureoles. Sulphur and possibly metal mobilization within these contact aureoles is essential in the formation of economic magmatic sulphide deposits. We performed heating and partial melting experiments on a black shale sample from the Paleoproterozoic Virginia Formation, which is the main source of sulphur for the world-class Cu-Ni sulphide deposits of the 1.1 Ga Duluth Complex, Minnesota. These experiments show that an autochthonous devolatilization fluid effectively mobilizes carbon, sulphur, and copper in the black shale within subsolidus conditions (≤ 700 °C). Further mobilization occurs when the black shale melts and droplets of Cu-rich sulphide melt and pyrrhotite form at ∼1000 °C. The sulphide droplets attach to bubbles of devolatilization fluid, which promotes buoyancy-driven transportation in silicate melt. Our study shows that devolatilization fluids can supply large proportions of sulphur and copper in mafic–ultramafic layered intrusion-hosted Cu-Ni sulphide deposits.

Effect of Shale Sample Particle Size on Pore Structure Obtained from High Pressure Mercury Intrusion Porosimetry

With the rapid development of unconventional oil and gas, the pore structure characterization of shale reservoirs has attracted an increasing attention. High pressure mercury intrusion porosimetry (HPMIP) has been widely used to quantitatively characterize the pore structure of tight shales. However, the pore structure obtained from HPMIP could be significantly affected by the sample particle size used for the analyses. This study mainly investigates the influence of shale sample particle size on the pore structure obtained from HPMIP, using Mississippian-aged Barnett Shale samples. The results show that the porosity of Barnett Shale samples with different particle sizes obtained from HPMIP has an exponentially increasing relation with the particle size, which is mainly caused by the new pores or fractures created during shale crushing process as well as the increasing exposure of blind or closed pores. The amount and proportion of mercury retention during mercury extrusion process increase with the decrease of shale particle size, which is closely related to the increased ink-bottle effect in shale sample with smaller particle size. In addition, the fractal dimension of Barnett Shale is positively related to the particle size, which indicates that the heterogeneity of pore structure is stronger in shale sample with larger particle size. Furthermore, the skeletal density of shale sample increases with the decrease of particle size, which is possibly caused by the differentiation of mineral composition during shale crushing process.

A novel technique for the modeling of shale swelling behavior in water-based drilling fluids

One of the most significant problems in oil and gas sector is the swelling of shale when it comes in contact with water. The migration of hydrogen ions (H+) from the water-based drilling fluid into the platelets of shale formation causes it to swell, which eventually increases the size of the shale sample and makes it structure weak. This contact results in the wellbore instability problem that ultimately reduces the integrity of a wellbore. In this study, the swelling of a shale formation was modeled using the potential of first order kinetic equation. Later, to minimize its shortcoming, a new proposed model was formulated. The new model is based on developing a third degree polynomial equation that is used to model the swelling percentages obtained through linear dynamic swell meter experiment performed on a shale formation when it comes in contact with a drilling fluid. These percentages indicate the hourly change in sample size during the contact. The variables of polynomial equation are dependent on the time of contact between the mud and the shale sample, temperature of the environment, clay content in shale and experimental swelling percentages. Furthermore, the equation also comprises of adjustable parameters that are fine-tuned in such a way that the polynomial function is best fitted to the experimental datasets. The MAE (mean absolute error) of the present model, namely Scaling swelling equation was found to be 2.75%, and the results indicate that the Scaling Swelling equation has the better performance than the first order kinetics in terms of swelling predication. Moreover, the proposed model equation is also helpful in predicting the swelling onset time when the mud and shale comes in direct contact with each other. In both the cases, the percentage deviation in predicting the swelling initiation time is close to 10%. This information will be extremely helpful in forecasting the swelling tendency of shale sample in a particular mud. Also, it helps in validating the experimental results obtained from linear dynamic swell meter.

Preliminary Experimental Study of Methane Adsorption Capacity in Shale After Brittle Deformation Under Uniaxial Compression

This paper presents a preliminary experimental study on methane adsorption capacity in shales before and after artificial deformation. The experimental results are based on uniaxial compression and methane isothermal adsorption tests on different shale samples from the Silurian Longmaxi Formation, Daozhen County, South China. Two sets of similar cylindrical samples were drilled from the each same bulk sample, one set was subjected to a uniaxial compressive simulation test and then crushed as artificial deformed shale sample, the other set was directly crushed as the original undeformed shale sample. And then we conducted a comparative experimental study of the methane adsorption capacity of original undeformed and artificially deformed shales. The uniaxial compression simulation results show that the failure mode of all samples displayed brittle deformation. The methane isothermal adsorption results show that the organic matter content is the main controlling factor of shale methane adsorption capacity. However, the comparative results also show that the compression and deformation have an effect on methane adsorption capacity, with shale methane adsorption capacity decreasing by about 4.26–8.48% after uniaxial compression deformation for the all shale samples in this study.

Acid Treatment as a Way to Reduce Shale Rock Mechanical Strength and to Create a Material Prone to the Formation of Permanent Well Barrier

Utilization of natural shale formations for the creation of annular barriers in oil and gas wells is currently discussed as a mean of simplifying cumbersome plugging and abandonment procedures. Shales that are likely to form annular barriers are shales with high content of swelling clays and relatively low content of cementation material (e.g., quartz, carbonates). Shales with large content of quartz and low content of swelling clays will be rather brittle and not easily deformable. In this paper we ask the question whether and to what extent it is possible to modify the mechanical properties of relatively brittle shales by chemically removing some cementation material. To answer this question, we have leached out carbonates from Pierre I shale matrix using hydrochloric acid and we have compared mechanical properties of shale before and after leaching. We have also followed leaching dynamics using X-ray tomography. The results show that removal of around 4–5 wt% of cementation material results in 43% reduction in Pierre I shale shear strength compared to the non-etched shale exposed to sodium chloride solution for the same time. The etching rate was shown to be strongly affected by the volume of fluid staying in direct contact with the shale sample.

3D rock minerals by correlating XRM and automated mineralogy and its application to digital rock physics for elastic properties

Digital rock physics (DRP) is an emerging technique that has rapidly become an indispensable tool to estimate elastic properties. The success of DRP mainly depends on three factors: acquiring a 3D rock structure image, accurately identifying 3D minerals, and using a proper numerical simulation method. Shales present a substantial challenge for DRP owing to their heterogeneous structure, composition, and properties from micron to centimeter scale. To obtain a sufficiently large field-of-view (FOV) image of a sample that reflects the detailed and representative internal structure and composition, we have developed a new DRP workflow to obtain large-FOV high-resolution digital rocks with 3D mineralogical information. Using the “divide-and-stitch” technique, a long shale sample is divided into several subunits, imaged separately by high-resolution X-ray microscopy (XRM), and then stitched to obtain a large-FOV 3D digital rock. An FOV of a rock cylinder (736 μm in diameter, 2358 μm in height, and 1 μm resolution) is used as an example. By correlating XRM and automated mineralogy, a large-FOV 3D mineral digital rock is obtained from a shale sample. Six mineral phases are identified and verified by automated mineralogy, and four laminae are detected according to the grain size, which offer a new perspective to study sedimentary processes and heterogeneities at the millimeter scale. The finite-difference method is used to compute the elastic properties of the large-FOV 3D mineral digital rock, and the results of Young’s modulus are within the limit of the Voigt/Reuss bounds. It also reveals that there is a difference in simulated elastic properties in the four laminae. The large-FOV 3D mineral digital rock offers the potential to explore the relationship between elastic properties and mineral phases, as well as the heterogeneities of elastic properties at the millimeter scale.

Effect of capillary pressure and geomechanics on multiphase fluid flow in rocks

<p>Understanding interactions between rock and fluids is important for many applications including CO<sub>2</sub> storage in the subsurface. Today significant effort is aimed at research on CO<sub>2</sub> flow through low-permeable shale formations. In some experiments, CO<sub>2</sub> is injected in a shale sample at a constant rate, and the upstream pressure exhibits rise until a certain moment followed by a decline, representing the so called breakthrough phenomenon. After the breakthrough, downstream flux significantly rises. This behavior was thought to be the result of fracture occurence or mechanical effects. <br><br>Here, we present a 3D numerical model of flow through experiments in shale. Our model accounts for poroelastic compaction/decompaction of shale, its time-dependent permeability, and two-phase flow, the fluid phases being CO<sub>2</sub> and air. The model also accounts for a capillary entry pressure threshold observed in experiments. The key feature of the model are saturation-based relative permeabilities which result in sharp overall permeability increases as the CO<sub>2</sub> moves through the shale sample. The model is implemented for 3D calculations with the finite volume method. Our results show that CO<sub>2</sub> breakthrough is a natural outcome of two-phase fluid flow dynamics and does not need a fracture to exhibit pressure behavior observed in experiments.</p>

Evaluating aromaticity changes with thermal stress at the single particle level for a suite of organic matter types from the Boquillas Shale (Texas, United States) via correlative Raman and reflection analyses

<p>Geochemical, petrographic, and spectroscopic indices that vary with compositional changes in petroliferous organic matter (OM) during thermal maturation are key petroleum system parameters used to understand petroleum generation. In unconventional shale source-rock reservoirs, where multiple, highly dispersed OM types may be present in intimate contact with surrounding mineral phases, OM molecular composition (e.g., aromaticity) is especially useful for informing structure-reactivity relationships representative of different OM types. Here, we employ microscale, in situ, and correlative Raman and reflectance approaches to evaluate aromaticity evolution for a suite of OM types (i.e., liptinite, micrinite, solid bitumen, vitrinite, and inertinite) at the single particle level across an artificial thermal gradient. Our samples include a marginally mature (vitrinite reflectance ~0.5%) Late Cretaceous Boquillas Shale from south Texas, United States, and two hydrous pyrolysis (HP) residues following reaction of the raw Boquillas Shale sample at 300°C and 330°C for 72 hours. Our data indicate that: (i) liptinite, micrinite, solid bitumen, vitrinite, and inertinite particles exhibit different aromatic signatures in the raw shale sample and (ii) these OM types, with the exception of inertinite, effectively experience similar changes in aromatic structure with thermal advance. Data also reinforce the concept that reservoir temperature may be a secondary factor in controlling the molecular composition of inertinite. These findings inform a broader understanding of how different petroliferous OM types evolve throughout thermal reactions and further demonstrate that correlative Raman spectroscopy and reflection analyses, combined with careful organic petrography, can provide complimentary estimates of OM molecular composition and thermal maturity.</p>

Effect of N2 and CO2 on shale oil from pyrolysis of Estonian oil shale

A kukersite oil shale sample from Estonia was pyrolyzed using a Fischer assay method under N2, N2/steam, CO2 and CO2/steam environments. The thermal behavior of the oil shale sample was also studied using TGA and DSC with similar conditions. Also, several properties of produced oils were measured and FTIR analysis was carried out to compare the molecular structure of the derived oils. The presence of steam increased the liquid and gaseous yields, and also caused a greater weight loss in the oil shale. The pyrolysis tests in both the CO2 and N2 atmospheres produced oils with relatively similar properties however, the molecular structure was different.