Imbibition Characteristics of the Barnett Shale Formation

Abstract

In order to understand the effect of injected stimulation fluids on nano-darcy permeability, naturally fractured shale reservoirs, an integrated study of spontaneous imbibition has been performed. In this study, oil recovery during spontaneous imbibition in naturally fractured shale samples was improved using different water formulations. Different water solutions were formulated by adding different amounts of HCl and NaOH to either distilled water or 2 wt% KCl-base brine solution. Eight water formulations, distilled water, 2% KCl brine, low pH HCl solutions (0.74-1.2), and high pH alkaline solutions (11.7-12.4) were examined to recover oil from shale rocks. Outcrop samples from the Barnett shale formation were used in this study. The samples were 2.54 to 3.81 cm in diameter and 0.762 to 5.08 cm in length. Firstly, we studied the average porosity of the used samples using CT Scanning. The average porosity was around 7%. Secondly, we studied the rock stability and spontaneous imbibtion of the different Barnett samples in distilled water, 2 wt% KCl, low pH solutions (0.74-1.2), and high pH alkaline solutions (11.7-12.4). During the spontaneous imbibition, the maximum oil recovery was 24% using distilled water and low pH solution of pH0.74 (3 wt% HCl in 2 wt% KCl base brine solution). Clay swelling can contribute to the Barnett oil recovery improvement by creating along bedding cracks. Oil recoveries from the Barnett shale can be improved by 56% when used 2 wt% NaOH solution and 88% when used 3 wt% HCl when added to 2 wt% KCl simulation base fluid. High pH solutions did not improve oil recoveries from the Barnett samples when added to distilled water due to pore plugging resulted from the combination of clay swelling with mineral dissolution. Low pH solutions showed along bedding cracks similar to distilled water effect on the Barnett shale samples that helped recovery accelerations, while higher pH solutions showed sever samples damage with higher alkaline concentrations (2 wt% NaOH).

A critical review of water uptake by shales

“…Several authors (Zhou et al 2014;Morsy and Sheng 2014;Makhanov et al 2014) have investigated the effect of fracturing fluid compositions on imbibition dynamics in shale. Zhou et al (2014) used shale samples from four different formations in the Horn River Basin in Canada and observed that the effect of fracturing fluid composition strongly depends on the clay content of shale rocks.…”

“…They found that for shale with higher clay content, 2% KCl and 2% KCl substitute (two different fracturing fluids) imbibed 10% to 40% less than 0.07% friction reducer (as fracturing fluid); whereas, for shale with low clay content, 0.07% friction reducer is imbibed 10% to 30% less than 2% KCl, but no noticeable difference was found between 0.07% friction and 2% KCl substitute. Morsy and Sheng (2014) used shale samples from Barnett formation and reported two important observations: i) high pH solutions mixed with distilled water resulted in pore plugging due to combination of clay swelling and mineral dissolution, whereas high pH solutions mixed with higher alkaline concentrations (2 wt% NaOH) resulted in severely damaging the samples, ii) low pH solutions induced bedding cracks resulting in accelerating the imbibition. Makhanov et al (2014) used several shale samples from Horn River Basin in Canada and reported two main observations: i) use of xanthan gum results in significant imbibition despite its high viscosity, ii) anionic surfactants can reduce imbibition rates by reducing the surface tension, which is reduced further if the surfactant is mixed with KCl salt.…”

A 3D model of hydraulic fracturing and microseismicity in anisotropic stress fields

“…x ¼ f 0 x r 0 z ¼ 19:5 MPa. The porosity of intact samples from the Barnett shale is measured with an average of 5.7% by Kale et al (2010), an average around 7% by (Morsy and Sheng 2014) and an average of 9.9% by Fu et al (2015). These porosity measurements cover a range from below 4% to more than 10%.…”

Experimental methods for studying the wetting properties of oil reservoirs: a review

“…Из за этого эксплуатация месторождения усложня ется. В связи с этим много работ было посвяще но изучению таких месторождении, в том числе и смачивающих свойств пород [Odusina, 2011;Wang, 2012;Shuler, 2011;Morsy, 2014;Alvarez, 2016]. Данные о смачиваемости породы позво лили правильно выбрать метод разработки этих месторождений.…”