Seawater-based fracturing fluids are used to generate a stable crosslinked fracturing fluid for higher formation temperatures primarily using two types of guar derivatives—HPG and CMHPG. Results are compared to other seawater-based fracturing fluid data in the literature, as well as to traditionally used freshwater-based fracturing fluid. A HP/HT rotational rheometer for viscosity measurements was utilized to assess the stability of the fracturing fluid. Chlorous-acid-based breakers were also tested in the fracturing fluid at various temperatures to assess effectiveness of reducing fluid viscosity. Additionally, a phosphonate-based scale inhibitor was used at various concentrations to mitigate the formation of scales that arise from the mixing of seawater and formation water. The concentration of the additives and consequent results are all provided to display the functionality of the crosslinked gel using seawater. Results confirmed that a dual-crosslinked seawater-based fracturing fluid stability was feasible, as viscosity remained greater than 500 cP for two hours. Freshwater-based fracturing fluid displayed longer gel stability primarily because of a lack of salts that hinder polymer hydration. The stability time varied owing to the thermal degradation of the polymer. The high total of dissolved solids of the seawater had minimal effect on the breaker, as it reduced the stability time of the seawater-based fracturing fluids by over 50%. The introduction of new, cost-effective fracturing fluid formulations introduces environmentally friendly ways to find substitutes for fresh water in hydraulic fracturing operations.

Laboratory analysis was conducted in order to study the effect of a phosphonate scale inhibitor on a mixture of hypersaline Arabian Gulf seawater and formation water under high temperature/high pressure (HT/HP) applications. The objective of this study was to identify the minimum scale inhibitor concentration required at various temperatures to achieve a cost-effective solution in minimizing the formation of common oilfield scales. Development of such a product would aid in the utilization of seawater-based fracturing fluids by controlling the scaling tendencies of the system, especially when exposed to formation waters. Utilizing a scaling software, various types of scales were modeled by testing different seawater/formation water ratios at temperatures ranging from 270 – 330°F. A dynamic scale loop was used which allowed seawater and formation water to be pumped into the system, thereby generating differential pressure data. The exponential increase in pressure would indicate scale formation. Various concentrations of scale inhibitor were then introduced to the mixtures and tested to determine the minimum scale inhibitor required for scale mitigation. Compatibility tests were also conducted to test for the efficacy of the scale inhibitor. Based on the scaling software, barite was identified as the primary scale generated. Barite scale has a low solubility of 2 mg/L and is one of the most difficult scales to mitigate. The highest concentration of barite scale occurred in a 50/50 ratio mixture of formation water and seawater. For all the temperatures tested, the scale loop was run at the concentration with the most barium sulfate present. The results for this research concluded that at 270°F and 300°F, the minimum scale inhibitor concentration was 2000 ppm and 1500 ppm, respectively. Both treatments successfully mitigated the following types of scales: barium sulfate, calcium sulfate(s), and strontium sulfate. At 330°F, the minimum scale inhibitor concentration was lower. This decreasing trend in scale inhibitor concentration as temperature was increased is attributed to the temperature constraint of phosphonate scale inhibitors. As a result, adding the phosphonate scale inhibitor contributed to the formation of calcium phosphonate complexes that led to the rise in pressure in the scale loop test. This hindered the efficiency of the treatment and portrayed the dramatic effects of temperature and inhibitor concentration on scale mitigation. This research pushes the thermal constraints of a phosphonate scale inhibitor up to 330°F to test its efficiency and overall treatment integrity. There are also fracturing fluid applications introduced utilizing a seawater source with one of the highest total dissolved solids (TDS) concentrations in the world. Barium sulfate and other scales were successfully mitigated at various high-temperature applications for these systems utilizing a phosphate scale inhibitor.