Seawater-based fracturing fluids provide greater flexibility when designing stimulation treatments for offshore environments by reducing delays in stimulation vessel scheduling and using an, essentially, unlimited supply of seawater, opposed to fresh water. Because seawater has a higher ionic strength than traditional fresh water, lower viscosity is observed from guar-based polymers. By comparison, the seawater can produce scaling precipitates when sulfate ions contact the calcium, barium, and strontium ions in the formation. The formed sulfate precipitates could lead to formation damage in the form of scaling, pore throats being clogged, and an overall reduction in production capacity. This paper presents an innovative polymer-based scale inhibitor (SI) to mitigate scaling issues from seawater with 4,000 mg/L sulfate when mixed with 200,000 mg/L total dissolved solids (TDS) formation water. From static bottle tests with seawater, 74% strontium sulfate inhibition was achieved at 300°F. To eliminate sulfate scaling issues, a nanofiltration (NF) membrane-based technique was used to filter seawater. The SI performance was tested by both static bottle tests at different mixing ratios and dynamic tube blocking tests at 300°F. Following static bottle tests, the key ion concentrations were determined using inductively coupled plasma (ICP) spectroscopy. Zero scaling was achieved by adding 300 mg/L SI. The fracturing fluid was prepared using a zirconate-crosslinked derivatized guar. The rheology of the fracturing fluid was measured with and without SI to investigate its influence on crosslinking and proppant carrying capacity at 300°F. High magnesium in the seawater consumes hydroxide ions and affects pH control. To obtain a stable fracturing fluid, the pH was optimized to minimize magnesium precipitation. Coreflooding experiments confirmed the addition of SI does not cause additional formation damage. Using NF-seawater in conjunction with proven SIs can provide effective treatment of seawater-based-fracturing fluids. The separation technique (NF) and chemical solution (SI) complement each other to neutralize scaling issues completely. This technique minimizes freshwater usage in fracturing, which can enable significant savings for offshore operations time and cost.

Hydraulic fracturing has been extensively used as an efficient method to enhance the hydrocarbon production, especially in tight formations. However, this technique has been associated with long-lasting formation damage challenge due to fracturing fluid filtrate leakoff. According to Laplace equation, this fluid leakoff results in a phenomenon called water blockage due to capillary forces. Recent studies have shown that surfactants can be used as an additive to fracturing fluids and they will reduce the required pressure to displace the injected fracturing fluids. In this study, the performance of two new nano-emulsion surfactants has been investigated. Nano-emulsion surfactant mixtures were prepared at different concentrations ranging from 0.5 to 5 gpt using field mixing water. Mixing water and representative field condensate samples were used to conduct both the surface tension and contact angle measurements at temperature range of 77-325°F. Laplace equation was used to calculate capillary pressure values based on surface tension and contact angle values. The results based on this study have illustrated the effectiveness of nano-emulsion surfactants to recover the fracturing fluid filtrate during flowback. The performance of these surfactants was investigated as a function of several parameters such as surfactant concentration, soaking time, and temperature. In addition, this paper explored the adsorption behavior of these surfactants on formation rock and the effect of nano-emulsion surfactants on the rock wettability. Optimal design parameters of these nano-emulsion surfactants to achieve significant enhancement in injected fracturing fluid recovery are also discussed.

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Acid treatments of carbonate formations are usually carried out using mineral acid (HCl), organic acids (formic and acetic), mixed acids (HCl-formic, HCl-acetic), or retarded acids. The major challenges when using these acids are their high corrosivity, fast reaction rate and health hazard. The improvement in corrosion inhibitors makes the use of a strong acid as high as 28 wt% HCl possible. The acid reaction rate can be controlled by increasing acid viscosity using gelling agent or emulsifying acid droplets, acid-in-diesel emulsion. While the issues of stimulation acids reaction and corrosion rates are relatively controlled, these acids health hazard rating of 3 by the National Fire Protection Association (NFPA) is a major concern. A health hazard rating of three is defined as an extreme danger where short exposure could cause serious injury. An acid replacement chemical that has no or minimum health hazard rating while still has the ability to dissolve carbonate rock would be a major forward step in stimulation technology. This paper presents the results of the study conducted on a synthetic stimulation acid (Syn-A) chemical, with health hazard rating of one and dissolving power similar to 15 wt% hydrochloric acid (HCl). An extensive experimental scheme including: thermal stability, dissolving power, acidity, compatibility, corrosion rate & inhibition and coreflooding on carbonate formation core plugs was conducted. The Syn-A was found to be thermally stable with similar dissolving power to 15 wt% HCl and lower corrosion rate. In addition, the Syn-A developed a breakthrough on core plugs with an average pore volume (PV) of 2.7 and approximately 3 folds increase in permeability.