Contaminated groundwater is a priority issue on the environmental agendas of developed countries. Therefore, there is an obvious need to develop instruments and decision-making mechanisms that allow the estimation of the risk to human health due to the presence of contaminants in soils and groundwater, in a fast and reliable manner. Thus, this study aims to assess whether the spilling of hydraulic fracturing fluids prior to injection has a potential risk to groundwater quality in the Kern County Sub-basin, California, by identifying the hydrological factors and solute transport characteristics that control these risks while taking into consideration the temperature rises due to climate change. The approach uses the concept of the groundwater pollution risk based on comparing the concentration of pollutants within the water table by using a predetermined permissible level. The current average annual temperature and that by the end of the 21st century was used to estimate the diffusion of benzene through three types of soil by using HYDRUS-1D software. The software was used to predict the contaminant concentration profile of benzene in the water table with special reference to the impact of surface temperatures. The results showed that an expected rise of the surface temperature by 4.3 °C led to an increase in the concentration of benzene by 2.3 μg/l in sandy loam soil, 6.8 μg/l in silt loam soil, and finally, 2.6 μg/l in loam soil. The results show that climate change can substantially affect soil properties and their chemical constituents, which then play a major role in absorbing pollutants.
Hydraulic fracturing becomes more difficult when confronted with a formation of high fracturing pressure. In such formations, acidizing before the main fracturing treatment provide a method to reduce fracture pressure. The aim of this paper was to investigate the evolution of fracture pressure in a wellbore with acidizing. Five experiments were conducted to study the mechanisms of acid damage on reservoir minerals and cementing materials properties. Consequently, a mathematical model to predict fracture pressure with acidizing has been established and verified by field data. The analysis results showed that it is possible to reduce fracture pressure with decreased rock strength and fracture critical stress intensity factor by means of acid damage. Acid damage destroys the crystal structure of mineral particles, breaks the crystalline layers in cementing materials, increases rock porosity and reduces the rock strength. In addition, as the acid concentration, formation temperature and acid treatment time increased, it was useful to reduce fracture pressure in the wellbore. Using the proposed model, we were able to select the optimal acid damage construction parameters to reduce fracture pressure.
In hydraulic fracturing, fracturing fluids are used to create fractures in a hydrocarbon reservoir throughout transported proppant into the fractures. The application of many fields proves that conventional fracturing fluid has the disadvantages of residue(s), which causes serious clogging of the reservoir's formations and, thus, leads to reduce the permeability in these hydrocarbon reservoirs. The development of clean (and cost-effective) fracturing fluid is a main driver of the hydraulic fracturing process. Presently, viscoelastic surfactant (VES)-fluid is one of the most widely used fracturing fluids in the hydraulic fracturing development of unconventional reservoirs, due to its non-residue(s) characteristics. However, conventional single-chain VES-fluid has a low temperature and shear resistance. In this study, two modified VES-fluid are developed as new thickening fracturing fluids, which consist of more single-chain coupled by hydrotropes (i.e., ionic organic salts) through non-covalent interaction. This new development is achieved by the formulation of mixing long chain cationic surfactant cetyltrimethylammonium bromide (CTAB) with organic acids, which are citric acid (CA) and maleic acid (MA) at a molar ratio of (3:1) and (2:1), respectively. As an innovative approach CTAB and CA are combined to obtain a solution (i.e., CTAB-based VES-fluid) with optimal properties for fracturing and this behaviour of the CTAB-based VES-fluid is experimentally corroborated. A rheometer was used to evaluate the visco-elasticity and shear rate & temperature resistance, while sand-carrying suspension capability was investigated by measuring the settling velocity of the transported proppant in the fluid. Moreover, the gel breaking capability was investigated by determining the viscosity of broken VES-fluid after mixing with ethanol, and the degree of core damage (i.e., permeability performance) caused by VES-fluid was evaluated while using core-flooding test. The experimental results show that, at pH-value ( 6.17 ), 30 (mM) VES-fluid (i.e., CTAB-CA) possesses the highest visco-elasticity as the apparent viscosity at zero shear-rate reached nearly to 10 6 (mPa·s). Moreover, the apparent viscosity of the 30 (mM) CTAB-CA VES-fluid remains 60 (mPa·s) at (90 ∘ C) and 170 (s - 1 ) after shearing for 2-h, indicating that CTAB-CA fluid has excellent temperature and shear resistance. Furthermore, excellent sand suspension and gel breaking ability of 30 (mM) CTAB-CA VES-fluid at 90 ( ∘ C) was shown; as the sand suspension velocity is 1.67 (mm/s) and complete gel breaking was achieved within 2 h after mixing with the ethanol at the ratio of 10:1. The core flooding experiments indicate that the core damage rate caused by the CTAB-CA VES-fluid is ( 7.99 % ), which indicate that it does not cause much damage. Based on the experimental results, it is expected that CTAB-CA VES-fluid under high-temperature will make the proposed new VES-fluid an attractive thickening fracturing fluid.