Political Conflict and Sung Ying-hsing during the Last Stand of the Ming Dynasty

Reservoir formations are often very heterogeneous and fluid flow is strongly determined by their permeability structure. Thus, when a scale inhibitor (SI) slug is injected into the formation in a squeeze treatment, fluid placement is an important issue. To design successful squeeze treatments, we wish to control where the fluid package is placed in the nearwell reservoir formation. In recent work1, we went "back to basics" on the issue of viscous SI slug placement. That is, we re-derived the analytical expressions that describe placement in linear and radial layered systems for unit mobility and viscous fluids. Although these equations are quite well known, we applied them in a novel manner to describe scale inhibitor placement. We also demonstrated the implications of these equations on how we should analyse placement both in the laboratory and by numerical modelling before we apply a scale inhibitor squeeze. An analysis of viscosified SI applications for linear and radial systems was presented both with and without crossflow between the reservoir layers. In this previous work, we assumed that the fluid being used to viscosify the SI slug was Newtonian1. However, the question has been raised concerning what the effect would be if a non-Newtonian fluid was used instead. We mainly consider the effect of shear thinning although our analysis is generally applicable if the non-Newtonian flow rate/effective viscosity function is known. We address the questions: (i) Does the shear thinning behaviour result in more placement into the higher or lower permeability layer (in addition to the effect of simple viscosification)? (ii) Can the shear thinning effect be used to design improved squeeze treatment?</p

Silicate Scaling Formation: Impact of pH in High-Temperature Reservoir and Its Characterization Study

Silicate scaling tends to form and be aggravated during high pH Alkaline Surfactant Polymer (ASP) floods and this silicate scale deposition affects oil production. Hence, it is important to examine the conditions that lead to silicate scale forming. The severity of the silicate scaling reaction, the type and morphology of silica/silicate scale formed in an experimental ASP flood were studied for pH values 5, 8.5, and 11, whilst the temperature was kept constant at 90 ℃. In addition, the impact of calcium ion was studied and spectroscopic analyses were used to identify the extent of scaling reaction, morphology type and the functional group present in the precipitates. This was performed using imagery of the generated precipitates. It was observed that the silica/silicate scale is most severe at the highest pH and Ca:Mg molar ratios examined. Magnesium hydroxide and calcium hydroxide were observed to precipitate along with the silica and Mg-silicate/Ca-silicate scale at pH 11. The presence of calcium ions altered the morphology of the precipitates formed from amorphous to microcrystalline/crystalline. In conclusion, pH affects the type, morphology, and severity of the silica/silicate scale produced in the studied scaling system. The comprehensive and conclusive data showing how pH affects the silicate scaling reaction reported here are vital in providing the foundation to further investigate the management and prevention of this silicate scaling. Copyright © 2022 by Authors, Published by BCREC Group. This is an open access article under the CC BY-SA License (https://creativecommons.org/licenses/by-sa/4.0