High Viscosity Friction Reducers (HVFRs) are often employed in hydraulic fracturing fluids to increase the proppant carrying capacity of slickwater fluids. However, it has been widely reported that the performance of HVFR fluids drops precipitously with even small amounts of salt. This study explores and reports the use of surfactants to alleviate the loss of performance of HVFR fluids due to salinity in the mix water. Fracturing fluids were prepared in the laboratory by mixing the HVFR at concentrations between 2 and 8 gal/1,000 gal with and without surfactant formulations. The viscosities of the fluids were measured on a TA Instruments DHR-3 rheometer using a concentric cylinder geometry. Both anionic and cationic HVFRs were tested with various surfactants. As expected, we observed that HVFR fluids display dramatic loss of viscosity with the addition of as little as 1% salt to the mix water. However, certain surfactant formulations were found to provide a significant boost in viscosity of HVFR fluids in brines over a wide range of shear rates. Increases in viscosity by a factor of as much as 10 times were observed, particularly at low shear rates. The ability of the surfactant formulations to enhance fluid viscosity was observed in both monovalent and divalent model brines, as well as brines that mimicked field produced water compositions. In addition, measurements were also performed in a slot flow device to determine if the results from the rheometer translated to proppant transport characteristics of the fluids. The slot flow results were found to correlate well with fluid viscosity measurements. The fluids containing the surfactant formulation transported nearly 4 times as much proppant as fluids not containing surfactant through a 2.5 ft. long rectangular slot of 0.5 in. thickness at a proppant concentration of 2 lb/gal. An obvious benefit of the approach proposed in this study is that it can enable the use of HVFR fluids in recycled and produced waters, providing both cost and sustainability benefits. Secondly, these surfactant formulations can reduce the amount of HVFR required to obtain a certain target viscosity in brine, thereby reducing the likelihood and potential severity of formation damage from HVFR residue.
Using flowback additives in slickwater fracturing fluids is a relatively recent innovation, and regained permeability testing using corefloods is the preferred performance evaluation method. The coreflood rig simulates the hydraulic fracturing process by injecting the fracturing fluid through a core under relevant pressure and temperature conditions, and measures the permeability and relative permeability changes during injection. Permeability measurements indicate whether the fracturing fluid damages the formation during hydraulic fracturing that in turn reduces oil productivity during flowback. While coreflooding is useful for comparing the performance of different flowback aids, it is unable to resolve the mechanisms associated with porescale transport. The goal of this study is to directly visualize and quantify the pore-scale dynamics of fracturing fluid injection and oil flowback using a microfluidic chip device and correlate these observations to the coreflood test results. Microfluidics-based measurements provide pore-scale visual evidence of the flowback dynamics, not achievable using conventional experimental methods such as the coreflood.
A common issue in thermal oil recovery is that a high-permeability path in the reservoir diverts steam from reaching the bulk of the pay region. Injection of thermal foams is an effective approach to improve the oil recovery factor by increasing the effective viscosity of gas phase. Conducting conventional laboratory testing on thermal foams is time consuming, often not representative of field conditions, and delivers limited amount of data. This study will outline a novel microfluidic method for rapidly screening foaming agents at reservoir-relevant pressures and temperatures. The objective of this study is to provide operators with a tool that can rapidly screen chemical additives before conducting a field pilot. Microfluidics is the study of fluid-flow at the micro-scale (typically tens to hundreds of microns). For measurement and analysis of fluid behavior and properties, microfluidics shows unique advantages including i) fast heat and mass transfer; ii) small amount of sample consumption; iii) full-factorial multiplexed analysis. In this study, microfluidic devices are fabricated from glass and silicon wafers in a clean-room environment. A network of microscopic channels etched in the silicon wafer emulates flow through the reservoir and allows reservoir engineers to visualize the foaming process and quantify foam stability under a variety of conditions. The microfluidic device has two parallel porous media sections with two permeabilities, which allows the comparison of foam velocity. The results of this study show that recently developed high molecular weight sulfonates, can form stable foams at 250°C. This study provides the first micro-confined visual data showing the stability of thermal foams at high-temperature and -pressure. A key observation is that the mechanism responsible for increasing the pressure-drop across a porous media may not always be the formation of foam. Some chemicals showed that deposits form in the chip and increase the pressure drop. This is proof that selecting the correct chemistry is critical to preventing reservoir damage. The speed at which the foam moves through the two porous media sections is an indication of the foam's ability to increase resistance in the reservoir. This study demonstrates a novel approach to screening thermal foams and describes the pore-scale mechanism of foam degradation at temperature. This is the first study showing visual evidence of how thermal foams perform at reservoir-relevant temperatures and pressures (250°C and 5 MPa).
Surfactants are used in gas well deliquification to generate foam to lift liquid condensates and brine from a well during gas production. In this paper, the effect of various hydrocarbon components typically found in natural condensates on selected foaming surfactants was studied. The screening methodology used a modified blender test to evaluate foam height and its half-life. The foaming results from the blender tests are reported for a number of alpha olefin sulfonates (AOS), alkyl ether sulfates (AES), and betaines at 25°C and ambient pressure. The surfactants were also evaluated using dynamic foam carry-over apparatus at ambient conditions for further validation. This work helps to elucidate problems associated with choosing the proper gas well deliquification surfactant suitable for a condensate of a specific composition.
The development of a new class of surfactants for high temperature steam foam applications has been investigated using both a new bulk foam screening test and core testing in the presence and absence of bitumen. A new screening methodology utilizing a high pressure cell fitted with viewing windows is described. Data is presented for the initiation and degradation rate of bulk foams for a number of surfactants at 190°C and 250°C. Two surfactants Agent X and Agent Z were examined in core flood in the presence and absence of bitumen. At both 190°C and 250°C, the foaming agents were capable of creating stable foam. Core flood results in ~15 D sand pack at 250°C show that in the absence of bitumen, Agent X and Agent Z were capable of creating apparent foam viscosities of 3.9 and 17.7 cP, respectively. In the presence of bitumen the foaming ability was decreased, but foams created by both surfactants still maintained apparent viscosities of >1 cP. Both surfactants produced foams that have shown shear thinning behavior under the conditions tested. Potential applications for high temperature foams are discussed in light of the results.
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