PVTX characteristics of oil inclusions from Asmari formation in Kuh-e-Mond heavy oil field in Iran

Incorporating PVT properties and compositional evolution of oil inclusions into reservoir engineering simulator protocols can enhance understanding of oil accumulation, reservoir charge history, and migration events. Microthermometry and volumetric analysis have proven to be useful tools in compositional reconstitution and PT studies of oil inclusions and were used to determine composition, thermodynamic conditions, physical properties, and gas-to-oil ratios of heavy oil samples from Asmari carbonate reservoir in Kuh-e-Mond heavy oil field in Iran. PVT properties were predicted using a PVT black-oil model, and an acceptable agreement was observed between the experiments and the simulations. Homogenization temperatures were determined using microthermometry techniques in dolomite and calcite cements of the Asmari Formation, as well. Based on the homogenization temperature data, the undersaturated hydrocarbon mixture prior to formation of the gas cap migrated with a higher gas-to-oil ratio from a source rock. According to the oil inclusion data, the onset of carbonate cementation occurred at temperatures above 45 °C and that cementation was progressive through burial diagenesis. PVT black-oil simulator results showed that the reservoir pressure and temperature were set at 100 bar and 54 °C during the initial stages of oil migration. Compositional modeling implies that primary and secondary cracking in source rocks were responsible for retention of heavy components and migration of miscible three-phase flow during hydrocarbon evolution. The PT evolution of the petroleum inclusions indicates changes in thermodynamic properties and mobility due to phenomena such as cracking, mixing, or/and transport at various stages of oil migration

Pneumomediastinum, pneumopericardium pneumothorax and subcutaneous emphysema in Iranian COVID-19 patients

Recently, spontaneous pneumomediastinum (PM), pneumopericardium (PP), pneumothorax (PT), and subcutaneous emphysema (SE) were reported as infrequent complications in coronavirus disease 2019 (COVID-19) patients in intensive care (ICU). Here we report these complications in nine Iranian patients of COVID-19. Nine patients with reported PM, PP, PT, and SE in COVID-19 who were hospitalized in Arya hospital, Rasht, Iran, for three months, were followed to record demographic data and clinical characteristics of these patients. In nine PM-developed patients, six cases represented PT, one patient with PP, and four patients with PT and SE. Four patents expired and only five patients survived. PM, PP, PT, and SE are uncommon complications in COVID-19 patients and were reported frequently in male patients. Early diagnosis and treatment could save the patients since these complications are related to poor prognosis and prolonged hospitalization. Patients with mild COVID-19 and mild pulmonary damage have a favorable outcome.

Brine estimation in shale gas reservoirs using wireline logging and laboratory data: a case study from Murteree shale, Cooper Basin, South Australia

The argillaceous nature of unconventional gas reservoirs presents ultra-complex lithology, nano-scale porosity and permeability. Petrophysical and mineralogical evaluation of these formations challenge high resolution diversified evaluation techniques to investigate first the dual storage mechanisms of natural gas and later to help in designing hydraulic fracturing techniques for maximum recovery of gas. Research work and contents in this paper are intended to develop some insight about post depositional diagenetic events in shale gas formations which have direct impact on brine evaluation in these types of overly clay rich reservoirs. Insights will help in understanding, reasons of uncertainties and doubts about controversial application of true formation resistivity (Rt) values from resistivity wireline logs in seconds Archie’s (1942) Equation in shale gas reservoir. Direct evaluation and assessment of porosity in shale is not reliable from wire-line logs alone; thus, it is essential that logs be calibrated with lab direct measurements such as QEMSCAN, XRD, and FIB/SEM. In the following sections, the geological background of study area is first discussed followed by our literature review and methodology used to determine different parameters for water saturation evaluation. Results are presented with the sensitivity study of different parameters. Some conclusive results are given at the end

Identification of potential locations for well placement in developed coalbed methane reservoirs

This study investigates well placement in developed coalbed methane (CBM) reservoirs. A workflow is developed to find potential locations for well placement within the reservoir. It consists of a reservoir simulator and statistical analysis. The application of this workflow is to reduce the need to perform computationally expensive simulations in large reservoirs to obtain potential locations for drilling an additional well. The workflow is also used to study the role of dominant reservoir properties in finding potential locations for well placement. The effects of permeability anisotropy, gas and water relative permeabilities, sorption time, and water content in well placement are discussed.Results demonstrate that permeability anisotropy results in the formation of elliptical drainage areas around the wells. When drainage patterns are orthogonal to the direction of placement of wells, the drainage area of the reservoir is large and penetrated into distant locations. This leads to a non-uniform drainage area and extends well placement options to distant locations. Comparison between well placement in two scenarios with different gas and water relative permeabilities shows that potential locations tend to be on a border region between existing wells and virgin area when water mobility is restricted by water relative permeabilities. This region has the advantage of having higher pressure and gas content compared to locations among existing wells. In this study, changing the sorption time does not affect the well placement within the reservoir. Except at very early times, gas production from presented reservoir models is mainly controlled by Darcy flow in cleat system (permeability-dominated) rather than diffusion process in coal matrix

Experimental and simulation study of foam stability and the effects on hydraulic fracture proppant placement

Foam has previously been used as fracturing fluid; however, there have not been enough study on foam stability and its effectiveness on proppant placement during hydraulic fracturing. In this paper, an experimental study was performed using free drainage method at 90 °C. Then, the rheological characterization of foam was produced based on dynamic foam quality change during foam drainage experiments and also based on viscosity breakdown by disproportionation. Subsequently, a 3-D hydraulically fracturing simulation was developed to evaluate the foam performance as a fracturing fluid using different vertical well scenarios. The results show that foam stability is dependent not only on the overall treatment time but also to fracture closure on proppant. For example, longer closure time accelerate proppant settling and accumulation at the bottom of the fracture, lowering propped area, and reducing productivity. The simulation results indicate that this lower productivity can be attributed to the final propped area, proppant distribution confirming the relationship between foam stability, foam rheology, proppant transport and fracture effectiveness

Development of a new approach for hydraulic fracturing in tight sand with pre-existing natural fractures

Hydraulic fracturing in tight gas reservoirs has been performed in the Cooper Basin for decades in reservoirs containing high stress and pre-existing natural fractures, especially near faults. The hydraulic fracture is affected by factors such as tortuosity, high entry pressures, and the rock fabric including natural fractures. These factors cause fracture plane rotation and complexities, leading to fracture disconnection or reduced proppant placement during the treatment. In this paper, rock properties are estimated for a targeted formation using well logs to create a geomechanical model. Natural fracture and stress azimuths within the interval were interpreted from borehole image logs. The image log interpretations inferred that fissures are oriented 30–60° relative to the maximum horizontal stress. Next, diagnostic fracture injection test (DFIT) data was used with the poro-elastic stress equations to predict tectonic strains. Finally, the geomechanical model was history-matched with a planar 3D hydraulic fracturing simulator, and gave more insight into fracture propagation in an environment of pre-existing natural fractures. The natural fracture azimuths and calibrated geomechanical model are input into a framework to evaluate varying scenarios that might result based on a vertical or inclined well design. A well design is proposed based on the natural fracture orientation relative to the hydraulic fracture that minimises complexity to optimise proppant placement. In addition, further models and diagnostics are proposed to aid predicting the hydraulically induced fracture geometry, its impact on gas production, and optimising wellbore trajectory to positively interact with pre-existing natural fractures