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.

Mineral scales frequently form during oil production as the result of changes in temperature, pressure, or the mixing of incompatible formation and injection waters. For hydraulic fracturing, there has been an ongoing effort to replace the use of fresh water with seawater or produced water to address the fresh water shortage issue in many areas in the world. When seawater is injected into the formation, the scaling tendency is inevitable. Among many different types of scale, barite scale, which is a product of the encounter of sulfate ions (typically abundant in seawater) and barium ions (exist at high concentrations in various formations), poses a serious problem. To effectively mitigate this serious scale issue, a combination of water treatment and chemical scale inhibitor is recommended. Nanofiltration (NF) technology has proven to be a reliable water treatment method that specifically removes sulfate ions from water sources with high sulfate content. This paper presents the results of a NF water-treatment process and discusses how the treatment process is a feasible method for barite scale inhibition. In addition, a comparative study of different organic polymers as scale inhibitors was also conducted. For barite scale inhibition in particular, sulfonate polymers were more effective than phosphonate polymers. Scale inhibitor development was conducted using standard evaluation methods, including static bottle testing and a dynamic scale loop. A new, quick laboratory method using ultrasonic vibration was also developed to evaluate scale inhibitor performance during the bottle testing. A combination of NF technology and the new scale inhibitor enabled a new technology to help prevent scale formation during fracturing with seawater or heavy brine water.

One of the most serious oilfield problems is scale deposition, particularly when two incompatible waters are involved. The control of scale deposition in high-pressure/high-temperature (HP/HT) wells has been challenging because most scale inhibitors lose effectiveness at high temperatures as a result of molecular instability. Hence, in the context of adapting to the continuous challenges of the oil and gas industry, along with the need to preserve freshwater resources in the Middle East, an in-depth study of the scaling results of mixing fracturing fluid developed using nanofiltered (NF) seawater with formation water containing high total dissolved solids (TDS) under HP/HT conditions is discussed. A series of dynamic experiments was performed using a DSR-6000 dynamic scale loop at 330°F and 3,000 psi. Additionally, static experiments were conducted at room temperature and 330°F for 2 and 24 hours, respectively. For both dynamic and static tests, two mixing ratios were tested: 80:20 and 50:50 mixtures of NF seawater:formation brine. The 80:20 mixing ratio represents the worst-case scenario according to scale advisor software results. Moreover, regained core permeability at 300 and 330°F and retained proppant pack conductivity tests were also performed. Results demonstrated that, for dynamic scale loop testing, the lowest concentration of scale inhibitor tested (250 ppm) achieved the passing criteria along with all higher concentrations for both mixing ratios. The static tests were also successful, with no precipitation formed. Regained core permeability was in the range of 77 to 89%. Finally, retained proppant pack conductivity result of 56% indicated good cleanup properties for NF seawater.

Injector wells comprise a small portion of the wells drilled globally; however, they pose unique drilling fluid challenges. Required for pressure support and production maximization, these wells can be costly if the desired level of injectivity cannot be achieved without first flowing them back. Traditional drill-in fluids (DIFs) contain starch and xanthan, the latter is known to impair injectivity due to its poor acid solubility. This paper describes the development of an aqueous reservoir drilling fluid targeted for injector wells. A brine-based reservoir drilling fluid was designed and developed utilizing a novel dual-functional xanthan-free additive to provide the necessary rheological and fluid loss properties without impairing injectivity. A thorough qualification was undertaken to evaluate fluid performance under a variety of conditions. Properties investigated included rheology, static-age stability, fluid loss, lubricant compatibility, and contamination susceptibility. A delayed-action filter cake breaker fluid was also designed and tested for suitability with the new reservoir drilling fluid. Return injectivity measurements were performed on both aloxite discs and core plugs to simulate the ability to achieve matrix injection without flowback. The novel additive provided excellent rheology, suspension, fluid loss control in the reservoir drilling fluid tested in the laboratory. Return injectivity testing demonstrated that the new DIF significantly outperformed existing fluids that contain xanthan or diutan without adjusting the delayed-action breaker formulation. The rheological performance of the new fluid was found to be stable and can be adjusted either though the novel additive concentration itself or through particle size optimization. Evaluation of the spent filter cake breaker effluent demonstrated that the novel additive was fully degraded, as compared to the traditional DIF in which an iodine test indicated the presence of whole starch persisting after several days contact with low-pH breaker. Existing DIF solutions function adequately for oil and gas producing wells given the low lift-off pressure resulting in minimal impairment to productivity. When considering injection wells, superior performance was achieved using this newly developed DIF which provides the potential to reduce well construction costs by eliminating the requirement to flow reservoir fluids back to a production facility before injecting.