The Challenges of Understanding Fluid in Fluid Density

2017 ◽  
Author(s):  
Anthony J. Petrosino ◽  
Michele J. Mann
Keyword(s):  
Fluid Density

Explanation of the Influence of Inflow Air Content on the Lift of Cavitating Hydrofoils

2018 ◽  
Vol 140 (8) ◽  
Author(s):  
Eduard Amromin
Keyword(s):  
Experimental Data ◽  
Theoretical Study ◽  
Lift Coefficient ◽  
Cavity Surface ◽  
Air Bubbles ◽  
Incoming Flow ◽  
Fluid Density ◽  
Air Content ◽  
Theoretical Results ◽  
Good Agreement

According to several known experiments, an increase of the incoming flow air content can increase the hydrofoil lift coefficient. The presented theoretical study shows that such increase is associated with the decrease of the fluid density at the cavity surface. This decrease is caused by entrainment of air bubbles to the cavity from the surrounding flow. The theoretical results based on such explanation are in a good agreement with the earlier published experimental data for NACA0015.

scholarly journals A silicon straight tube fluid density sensor

2007 ◽  
Vol 17 (8) ◽  
pp. 1657-1663 ◽  
Author(s):  
M Najmzadeh ◽  
S Haasl ◽  
P Enoksson
Keyword(s):  
Straight Tube ◽  
Fluid Density

A Novel Method to Determine the Drilling Fluid Density for Gypsum-Salt Layer

2021 ◽  
Author(s):  
Jitong Liu ◽  
Wanjun Li ◽  
Haiqiu Zhou ◽  
Yixin Gu ◽  
Fuhua Jiang ◽  
...  
Keyword(s):  
Drilling Fluid ◽  
In Situ Stress ◽  
Wellbore Stability ◽  
Shrinkage Rate ◽  
Fluid Density ◽  
Salt Layer ◽  
Rock Creep ◽  
Key Factor ◽  
Well Abandonment

Abstract The reservoir underneath the salt bed usually has high formation pressure and large production rate. However, downhole complexities such as wellbore shrinkage, stuck pipe, casing deformation and brine crystallization prone to occur in the drilling and completion of the salt bed. The drilling safety is affected and may lead to the failure of drilling to the target reservoir. The drilling fluid density is the key factor to maintain the salt bed’s wellbore stability. The in-situ stress of the composite salt bed (gypsum-salt -gypsum-salt-gypsum) is usually uneven distributed. Creep deformation and wellbore shrinkage affect each other within layers. The wellbore stability is difficult to maintain. Limited theorical reference existed for drilling fluid density selection to mitigate the borehole shrinkage in the composite gypsum-salt layers. This paper established a composite gypsum-salt model based on the rock mechanism and experiments, and a safe-drilling density selection layout is formed to solve the borehole shrinkage problem. This study provides fundamental basis for drilling fluid density selection for gypsum-salt layers. The experiment results show that, with the same drilling fluid density, the borehole shrinkage rate of the minimum horizontal in-situ stress azimuth is higher than that of the maximum horizontal in-situ stress azimuth. However, the borehole shrinkage rate of the gypsum layer is higher than salt layer. The hydration expansion of the gypsum is the dominant reason for the shrinkage of the composite salt-gypsum layer. In order to mitigate the borehole diameter reduction, the drilling fluid density is determined that can lower the creep rate less than 0.001, as a result, the borehole shrinkage of salt-gypsum layer is slowed. At the same time, it is necessary to improve the salinity, filter loss and plugging ability of the drilling fluid to inhibit the creep of the soft shale formation. The research results provide technical support for the safe drilling of composite salt-gypsum layers. This achievement has been applied to 135 wells in the Amu Darya, which completely solved the of wellbore shrinkage problem caused by salt rock creep. Complexities such as stuck string and well abandonment due to high-pressure brine crystallization are eliminated. The drilling cycle is shortened by 21% and the drilling costs is reduced by 15%.

The Prediction of Wellhead Pressure of Hydraulic Fracturing

2013 ◽  
Vol 405-408 ◽  
pp. 3323-3327
Author(s):  
Feng Shen ◽  
Zhou Wu ◽  
Nan Wang ◽  
Yong Ming Li
Keyword(s):  
Hydraulic Fracturing ◽  
Influencing Factor ◽  
Case Analysis ◽  
Fluid Density ◽  
Interaction Theory ◽  
Breakdown Pressure ◽  
Two Phase ◽  
Wellhead Pressure ◽  
Computing Method ◽  
Calculation Software

The accurate prediction of wellhead pressure in process of hydraulic fracturing is a keypoint to guide the design and construction of the fracturing, and does help in choosing appropriate wellhead equipment and pipeline. This paper calculates the formation breakdown pressure by using a self-made formation stress calculation software, analyzes perforation friction and near-wellbore friction on the basis of Michael theory, eatablishes a model of wellbore friction through Darcy-Weisbach equation and the momentum interaction theory of two-phase flow, and according to the composition of wellhead pressure, makes calculation software which can also analyze the influencing factor of wellbore friction, such as delivery rate, pipe diameter, fracturing fluid density and proppant size. Finally, case analysis verifies the accuracy of the computing method.

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