Friction reducers (FRs) are a vital component of slickwater fracturing fluids used in hydraulic fracturing operations. FRs, which are typically made up of high molecular weight polyacrylamide-based polymers, help decrease frictional pressure losses and improve the effectiveness of fracturing operations by allowing for higher fracturing (frac) injection rates at the same or lower surface pressures. By optimizing FR selection for field application, cost savings can be realized through reduction in chemical costs, reduction in equipment maintenance frequency, and rental savings. Furthermore, operations could be modified to use more produced water. Evaluating FR performance in the laboratory typically consists of running flow-loop experiments to measure pressure reduction in tubing or pipe over time. However, there is no industry-standard method for evaluating FR performance and different labs have developed their unique protocols and loop designs. To mitigate this deficiency, the project team designed and installed a FR evaluation flow loop and developed a protocol that effectively evaluates FR performance. The team compared performance of various FRs from selected FR suppliers focusing on three attributes: hydration time, maximum pressure reduction, and sustainability of pressure reduction over time. For a given test water, all candidate FRs were tested in the same conditions to allow direct comparison of FR performance. This work showed that pipe size, Reynolds number, and shear rate all affect friction reduction performance; but if testing is done under the same conditions, performance can be compared and ranked directly. Based on comprehensive testing to identify the best performing FRs for brackish, produced, and mixed water blends, a field test with the recommended candidates was conducted in support of a frac-chemical unbundling effort. FRs used in the field test were qualified using the in-house FR evaluation flow loop. Friction reducer performance in the field trial confirmed the FR lab evaluation protocol correctly ranks FR performance and enables scaling to field operation. There were no accepted methods to scale-up lab FR performance to predict field conditions and as accurate models continue to be developed, the main method for evaluating FR performance continues to rely on qualifying FRs based on lab-scale experiments. To bridge the gap, the project team developed an empirically based tool to improve FR selection using a comprehensive test matrix considering FR dosage, water salinity and water hardness. Development of this tool used constant test conditions so that consistent recommendations can be made.

High molecular weight HPAM's tend to be highly shear sensitive. Various components of polymer mixing and distribution systems pose risk to the integrity of HPAMs due to high shear experienced at valves, chokes and other flow control devices. At a minimum, this risk can severely impact chemical EOR operating cost due to polymer degradation and consequential viscosity loss of the injectate. Low-shear, low-cost polymer injection distribution systems have the potential to reduce polymer usage, maintain injection stream viscosity, and enable integration into brownfield facilities. Lower viscosity losses translate into optimized operating and capital cost for CEOR pilot and full field projects. The objective of this work was to determine the equipment (piping), process, and polymer parameters that affect viscosity loss due to shear degradation. In this work, polymers were evaluated from two different vendors. The effects of molecular weight, chemical concentration, and brine salinity on polymer sensitivity to viscosity loss due to shear degradation were investigated. Polymer solutions were either blended on site or purchased pre-blended in synthetic brine solutions. Pumped by a positive displacement, low-shear pump, the solutions flowed through a mass meter and were delivered to a distribution system component at various flow rates. For flow control devices, pressure differentials were adjusted at fixed flow rates. Polymer solution samples were collected upstream and downstream of the tested component. Samples were taken in no-shear sample collectors. Pressure upstream and downstream of the test component and flow rate were recorded during the flow test. Viscosity was measured with a Brookfield viscometer at ambient temperature. When higher concentration solutions were tested, viscosity was measured of diluted samples at target concentration to determine amount of shear degradation as evidenced by viscosity loss. Results indicate that viscosity degradation of polymer solutions does occur in flow control devices and is directly correlated to pressure differential across the pipe device. Internal geometry has little impact on the amount of degradation. Velocity has little impact on the amount of degradation. Polymer molecular weight and structure both affect the amount of degradation due to shear as does solution concentration. Generally, viscosified brine solutions will lose viscosity when flowed through devices with greater than 50 psi differential pressure in the range of 15-50% of initial viscosity. Using more concentrated polymer streams and diluting to target concentration after flow control will reduce the amount of viscosity loss. Based on the laboratory results, design and operating condition, recommendations can be made for polymer injection distribution systems to minimize shear degradation of the flowing viscosified brine stream.

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Chemical Enhanced Oil Recovery operations involve injecting polymer and surfactants for enhanced recovery. Some of the polymer and surfactant are produced in the form of emulsions. The emulsions need to be treated to recover the oil and reuse water for mixing new polymer for injection. New treatment methods are required to effectively break these emulsions. While chemical treatment and other methods are effective in breaking emulsions formed by electric submersible pumps (ESP's), these methods are not successful in breaking emulsions formed by injected chemicals for CEOR. Reuse of produced water is important in off-shore as well as some on-shore fields. Produced water re-injection requires mixing of fresh polymer with fluid containing produced polymer and traces of oil, which can cause potential incompatibility. Ideally, removal of all produced polymer using a viscosity reducer followed by injection of fresh polymer will improve facility reliability and uptime. Sodium hypochlorite (NaOCl or bleach) was evaluated as a viscosity reducer (VR). Bleach can reduce the viscosity of any HPAM by breaking down the polymer. Polymer destruction fortuitously causes a breakdown of emulsions which releases oil from water and results in improved water quality. After destruction of HPAM, excess bleach was neutralized by chemical means using a neutralizer. After neutralization, the resulting water is free of excess bleach and can be reused for mixing fresh polymer for injection without the risk of degradation of newly mixed polymer. Activating the VR (acidic VR) by pH adjustment can enhance the performance of VR dramatically. Improved oil separation as well as polymer removal can be realized using this technique.