Barite scaling during the low-flow, shut-in period in hydraulic fracturing operations during shale gas production has been intensively studied, but scaling during the stimulation periods when large volumes of water are injected at high flow rates has been mostly overlooked. Due to the variable nature of the injections, the kinetics of precipitation and the morphology of precipitated scale minerals vary due to different solute concentrations and hydraulic influences on fluid–rock interactions. Barite scaling at different stages of hydraulic fracturing was studied using flow-through experiments with fractured Marcellus shale cores. The experiments were conducted to mimic active stimulation injection at 0.3 mL/min for 4 days and then at low-flow or stagnant shut-in conditions at an injection rate of 0.01 mL/min or zero for 21 days. Monongahela River water, commonly used in fields in Southwestern Pennsylvania and West Virginia, has high sulfate concentrations and was used as the base water for synthetic hydraulic fracturing fluid (HFF). More than 80% of the barite formed inside the cores was from the stimulation period. Small round barite crystals (∼5 μm) were observed in the HFF before injection. Large euhedral barite (10–50 μm) covered the shale fracture surface in regions with apparent higher flow during the simulated injection period. Smaller (∼5 μm) barite precipitates were found over a larger area of the fracture surface in the shut-in, low-flow stage of the experiments. These findings indicate that mineral scale-related problems with gas production from hydraulically fractured wells likely relate to scaling minerals precipitating during the early stages of the process when fluid is being actively injected. Pretreatment of the HFF to reduce barite seed crystals before injection can be an important step for scaling control.

Barite scaling is a common problem in the shale gas industry. Barite precipitation due to rock-fluid interactions has been studied intensively in static and flow-through experiments, but the impact of flow pathway geometry on barite scaling remains a question. The complex fracture passages can lead to local concentrated geochemical interactions, resulting in spatially variable scaling distribution. In this study, designed patterns with channels and holes were milled in two Marcellus shale cores to represent the main flow pathways, where the slow flow travels from the inlet to the outlet, and near-stagnant zones, where the fluid is trapped. Hydraulic fracturing fluid, created using synthetic produced water and Monongahela River water as base fluid, was injected at 0.02 mL/min into the cores at 66 °C, a core pressure of 12.4 MPa (1800 psi), and a confining pressure of 13.8 MPa (2000 psi) for 28 days. For the core with both channels and holes, barite coatings formed in the channels and the holes, with thicker barite accumulations occurring on the non-patterned half of the core adjacent to the holes on the milled half. For the core with only holes, proppants were added to prop up the main flow pathways. Barite formed on the propped fracture surface. The proppants in the holes were covered with and glued together by barite. Such barite-proppant conglomerates were not found in the main propped fracture. These barite-proppant conglomerates may block transport pathways as well as the barite coatings.

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This paper presents a study of the relationship between permeability and effective stress in tight petroleum reservoir formations. Specifically, a quantitative method is developed to describe the correlation between permeability and effective stress, a method based on the original in situ reservoir effective stress rather than on decreased effective stress during development. The experimental results show that the relationship between intrinsic permeability and effective stress in reservoirs in general follows a quadratic polynomial functional form, found to best capture how effective stress influences formation permeability. In addition, this experimental study reveals that changes in formation permeability, caused by both elastic and plastic deformation, are permanent and irreversible. Related pore-deformation tests using electronic microscope scanning and constant-rate mercury injection techniques show that while stress variation generally has small impact on rock porosity, the size and shape of pore throats have a significant impact on permeability-stress sensitivity. Based on the test results and theoretical analyses, we believe that there exists a cone of pressure depression in the area near production within such stress-sensitive tight reservoirs, leading to a low-permeability zone, and that well production will decrease under the influence of stress sensitivity. IntroductionWithin the petroleum literature, there are many studies on the sensitivity of permeability to stress fields in tight reservoirs [1][2][3][4][5][6][7][8]. However, most of these studies are carried out in conditions under the low range of effective stress (e.g., generally no more than 7 MPa) as reference stress. Therefore, the extent of "damage" caused by stress or stress sensitivity is found to be very high from such studies. As a result, these studies indicate that low-permeability tight oil reservoirs are inadvisable to be developed under large pressure gradients, because of the formation's high sensitivity to change in effective stress. In fact, during well drilling and core sampling the state of stress within core samples will vary from the initial in situ state of stress, to a mud-hydrostatic-pressure state inside wellbores and to atmospheric conditions on the surface with stress release. If laboratory experimental conditions are not set approximately to actual in situ stress level of reservoirs, experimental results often show substantial changes in core pore-throat structures with changes in effective stress. The resulting stress sensitivity or formation deformation results cannot in general reflect the actual situation in formations. It has been shown in many experiments [9][10][11] that studies using stress fields lower than those for reservoir conditions overestimate the effects of stress on formation deformation (e.g., the results from laboratory experiments using conventional cores under low effective stress conditions fail to predict realistic changes in pore throats and structures). This paper presents results an...