Retention of Hydraulic Fracturing Water in Shale: The Influence of Anionic Surfactant
A tremendous amount of water-based fracturing fluid with ancillary chemicals is injected into the shale reservoirs for hydraulic fracturing, nearly half of which is retained within the shale matrix. The fate of the retained fracturing fluid is raising some environmental and technical concerns. Mitigating these issues requires a knowledge of all the factors possibly contributing to the retention process. Many previous studies have discussed the role of shale properties such as mineralogy and capillarity on fracturing fluid retention.
Hesham Abdulelah1, Syed M. Mahmood1, Sameer Al-Hajri2, Mohammad Hail Hakimi3, and Eswaran Padmanabhan1
1Shale Gas Research Group (SGRG), Institute of Hydrocarbon Recovery, Faculty of Petroleum & Geoscience, Universiti Teknologi PETRONAS, Seri Iskandar 32610, Perak, Malaysia. 2Department of Petroleum Engineering, Universiti Teknologi PETRONAS, Seri Iskandar 32610, Perak, Malaysia. 3Geology Department, Faculty of Applied Science, Taiz University, 6803 Taiz, Yemen
Received: 16 October 2018 / Accepted: 26 November 2018 / Published: 30 November 2018
However, the role of some surface active agents like surfactants that are added in the hydraulic fracturing mixture in this issue needs to be understood. In this study, the influence of Internal Olefin Sulfate (IOS), which is an anionic surfactant often added in the fracturing fluid cocktail on this problem was investigated.
The effect on water retention of treating two shales “BG-2 and KH-2” with IOS was experimentally examined. These shales were characterized for their mineralogy, total organic carbon (TOC) and surface functional groups. The volume of retained water due to IOS treatment increases by 131% in KH-2 and 87% in BG-2 shale. The difference in the volume of retained uptakes in both shales correlates with the difference in their TOC and mineralogy. It was also inferred that the IOS treatment of these shales reduces methane (CH4) adsorption by 50% in KH-2 and 30% in BG-2. These findings show that the presence of IOS in the composition of fracturing fluid could intensify water retention in shale.
Shale gas reservoirs are known to have ultra-porosity and permeability, thus exploiting them through conventional production methods is not economically feasible [1,2]. Hydraulic fracturing combined with horizontal drilling has been implemented to enhance gas production from shale, and they were proven to be commercial and effective approaches [3,4,5]. The aim of hydraulic fracturing in shale is to promote its permeability by opening the existing natural fractures and generating new fractures. It is accomplished by injecting a large volume of water-based fluid down a well at a suitable rate and pressure.
The resulting fracture networks within shale are typically kept open with proppants to encourage the gas flow from shale to the producing well thus improving gas recovery [6,7]. The fracking fluid is generally composed of water (~99.5%), proppants and a mixture of chemical additives that vary depending on the characteristics of shale reservoir [8,9].
One of the significant issues associated with fracking in shale is that massive amount of fracturing fluid (~5–50%) is retained in the formation after the fracking process [10,11]. For example, Ge  and Penny et al.  reported that only around 5% of the water is recovered the fracturing processes in shale while Nicot et al.  found less than 20%. Yang et al. , Makhnov et al.  and Reagan et al.  disclosed lower than 30% of fracking fluid in some other shale plays to flow-back whereas the other 70% of the injected fluid is believed to be retained by the shale reservoir. In some areas of the Barnet and Marcellus shales, the recovered water after fracking was nearly 50% [9,16].
The fracking water retention issue in shale has raised environmental [17,18,19,20] and technical concerns [21,22]. The role of retained water in contaminating the drinking water aquifers is a topic of debate . Vidic et al.  stated that the induced fractures outside the target formation could provide pathways for fracking fluid to migrate through. In the town of Pavillion, WY, the U.S. Environmental Protection Agency (EPA) observed water contamination in two shallow monitoring wells . Elevated levels of pH, specific conductance and traces of gas were confirmed in shallow groundwater possibly due to retained fracking water .
In Garfield County, the salinity of groundwater was reported to increase with fracking activities in the nearby wells . The rise in salinity with increasing the number of oil and gas wells could trigger the claim that migration from oil/gas wells nearby took place thus contaminating the shallow groundwater . Similarly, an official report by EPA  proposed that local water well in West Virginia was found contaminated with gel; conceivably due to leakage of fracturing fluid from an adjacent vertically fractured well. Birdsell et al.  concluded based on a two-dimensional conceptual model that the risk of aquifer contamination is reduced ten times by the combined influence of production well and capillary imbibition.
Myers  estimated the risk of groundwater contamination by fracking water by applying groundwater transport model to a Marcellus shale utilizing the pressure data from a gas well. He found that fracking fluid might reach groundwater aquifers in less than ten years. In Europe, investigating the possible in-situ contamination risk of hydraulic fracturing operation has gained considerable attention. The European Union (EU) has recently sponsored a project called “FracRisk” to explore the likely risks of the fracking operation. Under the “FracRisk” project, some generic and modeling studies were carried out to assess the potential impact of hydraulic fracturing on groundwater aquifers [27,28].
The amount of water used for hydraulic fracturing in shale is massive, the considerable proportion of retained fracturing fluid will necessitate using even more water which will adversely affect the water resources in some shale gas areas, which endure water scarcity . Besides its possible environmental issues, the retained fracking water can significantly impair the production of shale gas. Ge et al. , Gallegos et al.  and Sharma et al.  explained that retention of fracturing fluid was found to develop the water saturation near surfaces of the created fractures, which can prominently impact the gas relative permeability and productivity. Gas production will be significantly reduced as the water saturation reaches 40–50% [31,32].
Mitigating the issue of fracturing fluid retention in shale requires knowledge about the factors controlling this phenomenon. In the literature, more focus was given to the role of shale mineralogy  as a significant factor governing water retention during hydraulic fracturing. Many of the published studies [21,34,35] reports that clays, which are one of the primary minerals in shale have the affinity to imbibe water molecules due to their hydrophilic nature. However, the effect of some surface acting agents’ that are added into the fracking fluid mixture on water retention in shale was not given enough focus.
Common chemical additives in fracturing fluid are often surfactants [7,34,36,37,38]. Generally, they are intended to increase the viscosity of fracturing fluid to allow it to propagate within the target formation. An anionic surfactant that is added in fracturing fluid mixture is Internal Olefin Sulfate (IOS) .
Figure 1. Schematic diagram of the electrostatic interaction between (a) surfactant headgroup and positive-charged sites in shale, and (b) surfactant weak tail and negative-charged sites in shale. Modified after Zhou et al. .
Shales have a mixed-charged surface due to the coexistence of negative surface-charged and positive surface-charged minerals. Anionic surfactants have a negatively charged headgroup and positively charged weak tail. Figure 1 presents a depiction of the interaction between an anionic surfactant and a shale surface. Once anionic surfactant solution comes into contact with shale surface, either its strong headgroup will be attracted to the positively charged site (Figure 1a), or its weak tail will be attracted to the negatively charged sites in shale (Figure 1b). These interactions between the anionic surfactant and shale can alter its wettability and thus causing its water imbibition behavior to increase or decrease [34,39].
In this study, the effect of IOS (anionic surfactant) on water retention in two Malaysian shales was investigated. The shales were characterized for their total organic carbon (TOC), mineralogy, topology, and pore system. Water retention was then examined in two ways; measurements of water uptakes  and by utilizing the U.S Bureau of Mine Method (USBM)  adsorption/desorption method.
Materials and Methods
Table 1 lists the properties of the shales used in this study. The two shales differ in their mineralogy and the amount of organic carbon. The two shale shales were collected from two different Paleozoic black shale formations in Peninsular Malaysia. One shale “BG-2” was taken from Batu Gajah formation in Perak district. Batu Gajah formation was described by Baioumy et al.  to be a Carboniferous black shale outcrop formation composed of grey and black flaggy shales. The other shale “KH-2” was obtained from Kroh formation in Kedah district, which comes under the Ordovician-Devonian age. The Kroh formation is composed of a sequence of black carbonaceous shale and mudstone.
Table 1. Properties of the BG-2 and KH-2 shales.
IOS was used to treat the two shales in this study. Table 2 shows the available information about this surfactant. Surfactants are added into the hydraulic fracturing fluid to control its viscosity. In Bakken shale, a surfactant formulation including IOS was used to understand its imbibition behavior . IOS is also suitable to be used in hydraulic fracturing processes .
Table 2. Properties of IOS obtained from supplier and literature.
The chemical structure of IOS is shown in Figure 2. It has two alkyl groups (R) with 15 to 18 carbon atoms on the tail . To achieve the highest change in wettability, IOS was used at a concentration of 1 wt.%, which is well above its critical micelle concentration (CMC).
Figure 2. Chemical structure of Internal Olefin Sulfate (IOS).
Mineralogy and Topology
The mineralogy of the two shales was studied using x-ray diffractometer (Model: XPert3, PANalytical, Seri Iskandar, Malaysia). Powder forms of BG-2 and KH-2 shales were scanned from 5° to 65° with a step size of 0.026°. The basic principle of this technique is that electrons are produced from an X-ray tube and then accelerated towards the sample (shale in this study). Typical x-ray spectra are generated once electrons collide with the sample. The sample is continuously rotated by a motor, and the intensity of diffracted X-rays at an angle (2theta) is plotted. The interatomic spacing (d) is computed using Bragg’s law. Each D spacing value is a signature of some minerals that are then identified by comparing these values with the database.
The elements that constitute the mineralogy of both shales were investigated utilizing energy dispersive spectrometry (EDS) by a microscope (ZEISS, Seri Iskandar, Malaysia) at an accelerating voltage of 20 kV. Visualization of the mineralogy and pores in BG-2 and KH-2 shales was acquired exploiting Field Emission Scanning Electron Microscopy (FE-SEM, Model: Zeiss Supra 55VP). The fundamental of EDS and Images is that electrons beam is focused onto the sample surface hence producing secondary electrons, backscattered electrons, and characteristics X-ray. Both secondary and backscattered electrons are used for imaging. Characteristics X-ray is used for EDS. FE-SEM follow the same working principle but produces higher resolution images than SEM .
Total carbon (TC) analyzer (Model: Multi N/C 3100, Analytik Jena, Seri Iskandar, Malaysia) was utilized to measure the percentage of the TOC in BG-2 and KH-2 shales. Before the measurements, the two shales were treated with Hydrochloric acid (HCL) of 37% concentration to remove the inorganic carbon. The TC analyzer utilizes the combustion approach to determine the TOC. After the sample is loaded into a ceramic boat, the amount of carbon is then determined by combustion in an oxygen environment at 1200 °C. The resulted carbon dioxide is then measured by a detector, and then carbon % can be calculated.
Fourier-Transform Infrared Spectroscopy (FTIR)
The FTIR spectra of the two shales “BG-2 and KH-2” were obtained using a Perkin Elmer (Seri Iskandar, Malaysia) spectrometer. The measurements were carried out to obtain the abundant structures in both shales. The procedures for FTIR spectroscopy involve emitting a photon to a molecule hence exciting it to higher energy level. The molecular bonds at the higher energy state vibrate at varying wavenumber. Each wavenumber corresponds to a particular functional group (e.g., C=O) . FTIR spectroscopy has been utilized by many researchers to decipher the existing functional groups in many materials including but not limited to rocks [46,47] and chemicals . In this study, FTIR was carried out to unravel the surface functional groups in the two shales to support the mineralogy and TOC results. Before the measurements, the two shales were dried for 12 h.
To assess the affinity of the two shales towards water and surfactant solution, contact angles between the polished shale surfaces and water/surfactant solution were measured. The measurements were obtained using Vinci’s interfacial tension meter (IFT, model IFT 700, Vinci Technology, Seri Iskandar, Malaysia) by the Sessile Drop Method. The baseline wettability of the two shales was assessed using a droplet of pure water on their polished surfaces. Their wettability for anionic surfactants was then determined using a droplet of 1 wt.% IOS solution.
Direct Measurement of Water Retention
The water retention phenomenon in the two shales was evaluated utilizing the conventional natural stone method  at ambient condition under two cases; baseline and with IOS solution. The procedure includes immersing 100 g of each shale in pure water/surfactant solution in a desiccator under continuous vacuuming to remove the trapped air noted. When equilibrium was achieved, the retained water for the two shales was then calculated using mass balance.
Indirect Measurement of Water Retention
Figure 3 displays the schematic of the adsorption column used in this study. It is well known from the literature that water retention in shale impairs gas flow [19,30,31,50]. The measurements were carried out to investigate the change in gas adsorption in “BG-2 and KH-2” shales due to treatment by IOS solution. To achieve that, the pressure across the adsorption column was monitored during CH4 adsorption.
Figure 3. Schematic of Adsorption/Desorption Experimental Set-up.