Low salinity waterflooding for a carbonate reservoir: Experimental evaluation and numerical interpretation Ramez A. Nasralla a, * , Hassan Mahani a , Hilbert A. van der Linde a , Fons H.M. Marcelis a , Shehadeh K. Masalmeh b , Ekaterina Sergienko a , Niels J. Brussee a , Sebastiaan G.J. Pieterse a , Saptarshi Basu c a Shell Global Solutions International B.V., The Netherlands b Shell Abu Dhabi, United Arab Emirates c Shell India Markets Pvt. Ltd., India ABSTRACT Several laboratory studies and some field trials have already demonstrated the potential of lowering the injected brine salinity and/or manipulating composition to improve oil recovery in carbonate reservoirs. Laboratory SCAL tests such as coreflooding and imbibition are key steps to screen low salinity waterflood (LSF) for a particular field to (i) ensure that there is LSF response in the studied rock/oil/brine system, (ii) find the optimal brine salinity, (iii) extract relative permeability curves to be used in the reservoir simulation model and quantify the benefit of LSF and (iv) examine the compatibility of injected brine with formation brine and rock to de- risk any potential scaling or formation damage caused by fines mobilization. This paper presents an extensive LSF SCAL study for a carbonate reservoir and the numerical interpretation of the tests. The SCAL experiments were performed at reservoir conditions using reservoir core plugs, dead crude oil and synthetic brines. The rock was characterized using porosity-permeability measurement semi- quantitative, X-ray diffraction (XRD), scanning electron microscopy (SEM), and mercury intrusion capillary pressure (MICP) techniques. The characterization work showed that the plugs can be classified into two groups (uni-modal and bi-modal) based on pore throat size distribution which correlated with porosity-permeability cross-plots. The SCAL experiments were divided in two categories. Firstly, spontaneous imbibition and qualitative unsteady-state (USS) experiments were performed to demonstrate the effect of low salinity brines. In addition, these experiments helped to screen different brines (seawater and different dilutions of seawater) in order to choose the one that showed the most promising effect. Secondly, quantitative unsteady-state (USS) experiments were conducted and interpreted using numerical simulation to extract relative permeability curves for high salinity and low salinity brines by history-matching production and pressure data. The main conclusions of the study are: 1- The spontaneous imbibition and qualitative USS experiments showed extra oil production when switching from formation brine to seawater or diluted seawater subsequently, 2- Oil recovery by LSF can be maximized by injection of brine at a certain salinity threshold, at which lowering the brines salinity further did not lead to additional recovery improvement, 3- The LSF effect and optimal brine salinity varied in different layers of the reservoir which indicates that within the same reservoir the LSF effect is quite dependent on the rock type/property and mineralogy, 4- The quantitative USS showed that LSF can improve the oil recovery factor by up to 7% at core scale compared to formation brine injection. 1. Introduction Low-salinity waterflooding (LSF) in sandstone rock has attracted substantial interest in the E&P industry due to its potential for incre- mental oil recovery over a conventional water flood. Numerous labora- tory and some field experiments have shown that oil recovery from sandstone can be improved by lowering the total salinity and manipu- lating of ionic content of the injected water (see the review by Morrow and Buckley, 2011). The main benefit of LSF is acceleration of oil production due to wettability alteration and on top of that improved injectivity, lowering of reservoir souring and scaling compared to produced water re-injection (PWRI) (Collins, 2011; Sorop et al., 2013). It is operationally similar to conventional waterflooding and has usually lower CAPEX and OPEX than other IOR/EOR techniques. The same concept has been extended to carbonate rocks. Various laboratory studies such as contact angle measurements (Alotaibi et al., 2010; Chandrasekhar and Mohanty, 2013; Mahani et al., 2015), imbi- bition tests (Webb et al., 2005; Zhang and Austad, 2006; Strand et al., 2006; Zhang et al., 2007; Romanuka et al., 2012) and coreflooding ex- periments (Yousef et al., 2011; Gupta et al., 2011; Al-Harrasi et al., 2012; Nasralla et al., 2016; Shehata et al., 2014) have shown a positive low * Corresponding author. E-mail address: ramez.nasralla@shell.com (R.A. Nasralla). Contents lists available at ScienceDirect Journal of Petroleum Science and Engineering journal homepage: www.elsevier.com/locate/petrol https://doi.org/10.1016/j.petrol.2018.01.028 Received 25 July 2017; Received in revised form 10 January 2018; Accepted 11 January 2018 Available online 12 January 2018 0920-4105/© 2018 Elsevier B.V. All rights reserved. Journal of Petroleum Science and Engineering 164 (2018) 640–654