Experimental study and modeling of water-based fluid imbibition process in Middle and Lower Indus Basin Formations of Pa
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ORIGINAL PAPER-EXPLORATION ENGINEERING
Experimental study and modeling of water‑based fluid imbibition process in Middle and Lower Indus Basin Formations of Pakistan Muhammad Arqam Khan1 · Javed Haneef1 · Shaine Mohammadali Lalji1 · Syed Imran Ali1 Received: 29 January 2020 / Accepted: 8 October 2020 © The Author(s) 2020
Abstract Wellbore instability is one of the major problems that arise in drilling shale formations. Drilling in these formations may lead to breakouts and induce fractures. In Pakistan, drilling companies face quiet a number of formations that are shaly in nature and are candidates for wellbore instability issues. To counter these issues, it is required to have good understanding about the composition of the shale and its chemical reactivity with drilling fluids. Shale samples of three different formations have been obtained. These samples belong to two different regions of Indus Basin of Pakistan and were subjected to cation exchange capacity test and X-rays diffraction analysis to determine the reactivity and mineralogy, respectively. The samples were then tested for swelling properties using linear dynamic swell meter. The testing was done in two different water-based drilling fluids. The increase in height and swelling percentage for each sample was then recorded against each type of drilling fluid. A comparative analysis was done as to what type of drilling fluid systems out of the two used in the swelling test would best inhibit the swelling nature of shale for each formation in these regions of Pakistan. Finally, analytical and numerical modeling was performed on each shale sample. It was observed that the swelling parameter A (total swelling) increases significantly for Middle Indus Basin Shale Formation, and on the contrary, the filtration term (C) becomes independent of time after certain period of testing. Keywords Cation exchange capacity · Shale · Analytical modeling · Numerical modeling wellbore instability · XRD Abbreviations A Total swelling B Swelling at a particular instant of time C Filtration term t Time CEC Cation exchange capacity MBT Methylene blue test XRD X-rays diffraction YP Yield point PV Plastic viscosity
* Muhammad Arqam Khan [email protected] Javed Haneef [email protected] Shaine Mohammadali Lalji [email protected] Syed Imran Ali [email protected] 1
Department of Petroleum Engineering, NED University of Engineering & Technology, Karachi, Pakistan
PHAP Partially hydrolyzed polyacrylamide RMS Root-mean-square
Introduction One of the major technical issues of the oil industry is the instability of the wellbore (Van Oort et al. 1996; Van Oort 2003; Muniz 2005; Stankovic 2010). The most common reason for this problem is considered to be the presence of shale formation (Chenevert 1998; Al-Bazali 2009). During drilling, over 75% of the formations encountered are shaly in nature and more than 90% of the times cause severe wellbore instability problems while drilling is being performed through them (Mody and Hale 1993; Lal 1999; Al-Baz
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