ObjectivesThe study aims to investigate the rate of clinical depression in the adult population during the COVID-19 pandemic, as well as the changes in anxiety, distress, suicidal ideation, and their relations with several personal and interpersonal/social variables.MethodsThis is an epidemiological, non-interventional study. It is part of an international multi-center study, with the main site at the Aristotle University of Thessaloniki, in Greece (COMET-G Study). We are presenting aspects of the research involving the Canadian site, based on 508 Canadian responders to the online survey (QAIRE).ResultsOf the 508 responders, 72.2% were females aged 42.57 ± 14.00 years; 27.2% were males aged 42.24 ± 15.49 years; and 0.6% were others aged 46.33 ± 17.79 years. Increased anxiety during the lockdown was reported by 69.3% of those surveyed. The rate of suicidal thoughts increased in 19.5% of participants during the lockdown. Depression was reported by 22% of responders, while distress was present in 18.4%. We found a greater prevalence of depression, but not distress, in individuals with a history of any mental disorder. Based on the multiple regression analysis, we found four CORE factors equally influencing the changes in mental health during the lockdown (gender, quality of sleep, family conflicts, and changes in daily routine). In the Canadian population, two major changes acted as protective factors, significantly expressed when compared with the worldwide tendencies: fewer financial difficulties; and an increase in religious beliefs.ConclusionThe rate of major depression, distress, and suicidal ideation was higher in Canadians than in the worldwide population (per COMET-G), but the relative risk to develop depression in the presence of a history of mental disorders was lower. Almost 90% of Canadians believed in the real story of COVID source of provenience.

The key challenge in unconventional gas plays covering vast geographical areas is locating the regions in the reservoir with the highest combination of reservoir and completions quality. This allows operators to evaluate not only the richness of their resource but also the ability of the reservoir to produce hydrocarbons in commercial quantities. This paper discusses hydraulic fracturing designs targeting tight gas in horizontal wells drilled in the Apollonia tight chalk formation in the Abu-Gharadig basin, Western Desert, Egypt through the integration of laboratory, geological, petrophysical, geomechanical, fracture simulation, and diagnostic fracture injection test (DFIT) analysis. Laboratory testing, which included scanning electron microscopy (SEM) and X-ray diffraction (XRD), was conducted to determine mineralogy and potential damage mechanisms. Fracturing fluid chemistry was tested and optimized using core plugs from representative reservoir rock (fracture conductivity, fracturing fluid compatibility, surfactant type, fracture regain permeability, and scale tendency). Geomechanical rock properties derived from advanced petrophysical analysis of newly acquired high-definition triple-combo full-wave sonic logs and core samples were combined with geological parameters and potential treating schedules to develop sophisticated fracture simulation models. These models were then refined with in-situ reservoir data obtained from DFIT analyses to derive the final fracturing treatment design. The stimulation model was built using a three-dimensional (3D) geological model with multidisciplinary inputs, including formation properties, in-situ stresses, natural fractures, and completion parameters (i.e., well orientation, stage and perforation cluster spacing, fluid volume, viscosity, and proppant volume, size, and ramping schedule). The integration of all available data resulted in an optimized fracture design that helped reduce both cost and formation damage, thus improving flowback, long-term productivity, and profitability from this tight formation.

Fields in offshore Mexico present different challenges to maximizing resource recovery due to the reservoir characteristics and completion configurations. Acidizing of high temperature (HT) dolomitic reservoirs (290 °F/143 °C) in the maritime fields represents the primary stimulation option due to existing well parameters restricting treatment designs to matrix rate conditions. Acidizing treatments are typically based on HCl and organic acids and for the first time a multifunctional, low viscosity, retarded HCl acid is also available. Laboratory wormhole tests were conducted for matrix injection but also in a pseudo-acid fracture condition (split-core) in order to establish feasibility for future stimulation designs. Three acid blends were used, a blend of organic acids (OA), a mixture of HCl and organic acid (HA), and a polymer free retarded HCl acid (HRMA). The cores tested correspond to a particular well and X-ray Diffraction (XRD) analysis confirms it is >98% dolomite. CT imaging corroborates the heterogeneous permeability due to primary and secondary porosity systems (5% – 10% and 10% – 15%). The pore volume breakthrough of each acid blend was determined for two cores of similar porosity under same constant injection rate. Results indicate the organic acids blend (OA) can have better injectivity when flow rate is much higher than the HCl/Organic acid (HA) blend. A core with 10X lower permeability (0.1 – 0.5 mD) was tested with new Retarded HCl acid (HRMA) using same injection rate as the other acid blends. Results indicate that Retarded HCl (HRMA) does not cause core facial dissolution under unoptimized injection rate. The wormhole patterns generated for the HCl/Organic acid (HA) blend show good distribution and for Retarded HCl (HRMA) show enhance acid containment (less ramification). Both HCl acid blends (HA and HRMA) are suitable for dolomitic acidizing under different injection rates, while the purely organic acid blend is more adequate for high rate injection. Notably acidizing of dolomitic reservoirs can be highly efficient under optimized conditions and future work with non-retarded and retarded acids can systematically drive pumping engineering designs. The Retarded HCl acid (HRMA) has multifunctional properties including scale inhibition and lower HCl reactivity.

Concerns by regulatory authorities regarding cumulative effects or reservoir adsorption of hydraulic fracturing fluid have increased, with an overall focus on fracturing fluid additives. Operators do not always obtain adequate core materials to fully evaluate additive effectiveness or to belay regulatory concerns regarding the cumulative interaction effects of fracturing fluids with the formation. Without these materials, operators are often required to representatively sample post-fracturing fluids and hypothesize the volumes of additives remaining in the formation, material balancing on a qualitative post-frac testing basis, which can be highly unrepresentative.This paper presents the results from a study from a prospective shale gas interval where formation materials or cuttings were sampled across a representative producing interval, offsetting the proposed multistage fracturing treatment. The processes of how the fluid formulation was optimized using established qualitative procedures for clay sensitivity (i.e., capillary suction testing) and then further evaluated for surfactant requirements (e.g., tensiometry) are demonstrated. Following final fluid formulation, interactive testing with reservoir materials was performed, providing insight into the level of fluid and additive interaction that might result between the formation and the proposed fluid. This study provides practical approaches to testing and defines benefits and limitations of employing these approaches to belay potential concerns evolving related to fracturing fluid interaction within reservoirs and their cumulative effects.

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