Development of Seawater-Based Fracturing Fluid for High-Temperature Wells

Abstract

The development of a high-temperature seawater-based fracturing fluid has received much attention because it offers a solution to fresh water shortages; however, the rheological properties suffer significantly as a result of interactions between dissolved ions with fluid components. Various strategies have been investigated to address this challenge, including seawater treatments that ultimately remove the highly soluble and insoluble ionic moieties to yield a fracturing fluid with reliable rheological characteristics. Most polymer-based fracturing fluids have limited salt tolerance. Interactions between the polymer and divalent cations in seawater inhibit proper polymer hydration, thus preventing generation of an elastic polymer network and potentially affecting the crosslinking mechanism. In this study, concentrations of critical ions in seawater were reduced using a reliable seawater treatment. This treatment allowed a reliable fluid at higher temperatures and also considerably reduced the scaling tendency of the fluid. The fluid presented herein, designed in the treated seawater, yields a stable elastic polymer network when used in conjunction with stabilizing additives and is capable of effectively delivering proppant down hole. This newly developed formulation uses a combination of instant and delayed crosslinkers and additional stabilizing additives required at optimum concentrations to yield a stable fluid system in the treated seawater. At high temperatures, the addition of typical ion sequestration agents failed to eliminate the negative interaction between dissolved ions and fluid stability, thus requiring water pre-treatment. The fluid system exhibits reliable rheological properties and yields a clean broken fluid for excellent proppant pack cleanup in high total dissolved solids (TDS) waters up to 350°F. Typical guar-based fracturing fluids require a high pH (greater than 10) to maintain rheological stability at high temperatures. The fracturing fluid presented herein was developed at pH 9 in treated seawater and maintained its elasticity and viscosity over a long period of time at temperatures up to 350°F. An added benefit of controlling the pH and not surpassing pH 9.5 was also revealed—scale control. This study discusses the development of a new seawater-based fracturing fluid for use in high-temperature wells. This can result in a paradigm shift in source water use for hydraulic fracturing.

Seawater-Based Fracturing Fluid: A Review

“…In order to reduce the scaling propensity during fracturing treatments utilizing seawater-based fluid when combining with high TDS formation water, the nanofiltration (NF) of seawater was introduced. , It was discovered that the scaling issues during fracturing with seawater-based fluid may be effectively minimized by combining nanofiltration with the use of scale inhibitors, and it was determined that this combination is suitable for field applications. Nanofiltered seawater has been found to work well with scale inhibitors and is able maintain its rheological qualities for extended periods of time at temperatures as high as 350 °F. , In one study, it was found that no scale inhibitor was needed to produce negligible precipitation in mixtures of NF seawater and formation water. The reduced sulfate concentration of the NF seawater predicted a decrease in precipitates.…”

“…Obtaining fresh water has become difficult in some fields due to the high water transportation costs from the source to the wellsite, as well as rising limits on freshwater supply . Conventional wells use 200 000 gallons of water for hydraulic fracturing, while unconventional wells can use up to 16 million gallons. − For example, fracturing shale and tight sandstone formations often require more than 1 million gallons (3700 m 3 ) of water per well . This method uses a lot of water, damages the formation, and restricts future savings.…”

“…When comparing the same formulations between seawater and fresh water, it is clear that fluid instability increases with temperature. Polymers are known to precipitate out of solution once they reach their cloud point, as evidenced by numerous case studies . Salts have the potential to alter the cloud point of polyelectrolytes by shielding the electrostatic interactions between the charged groups.…”

“…Incorporating water molecules into the polymer via this interaction creates a strong polymer network. Proppant can be transported downhole and into the fracture network via the cross-linking mechanism, which takes place when cross-linker molecules (such as borate or metal) ,, engage with chemical moieties on numerous polymer strands. Because the cations in seawater disrupt the hydrogen bonds between the polymer and water, the fluids have a much lower viscosity.…”

“…14 Conventional wells use 200 000 gallons of water for hydraulic fracturing, while unconventional wells can use up to 16 million gallons. 15 − 19 For example, fracturing shale and tight sandstone formations often require more than 1 million gallons (3700 m 3 ) of water per well. 20 This method uses a lot of water, damages the formation, and restricts future savings.…”