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Aderibigbe, Aderonke (Texas A&M University) | Cheng, Kai (Texas A&M University) | Heidari, Zoya (Texas A&M University) | Killough, John (Texas A&M University) | Fuss, Tihana (Saint-Gobain Proppants) | Stephens, Walter T. (Saint-Gobain Proppants)
Abstract Reliable detection of propping agents in fractures has been a challenge for the petroleum industry. Researchers are currently investigating the application of nanoparticles as contrast agents for reservoir characterization and advanced reservoir surveillance. This paper demonstrates the use of nanoparticles as contrast agents mixed with proppants that can enhance signals from borehole geophysical measurements, thereby improving the detection of proppants in hydraulic fractures. The methods used in this paper study include both laboratory experiments and numerical simulations. The experimental approach consists of (a) synthesizing paramagnetic nanoparticles and (b) carrying out a series of magnetic susceptibility core logging measurements, using the superparamagnetic nanoparticles mixed with proppants. Numerical simulations are performed simultaneously to show that the distribution of nanoparticles remain concentrated in hydraulic fractures as is demonstrated in our experimental work. We developed a two-phase flow model to investigate the spatial distribution of nanoparticles when they are injected into a hydraulically fractured porous media, in which the hydraulic fractures are filled with propping agents. Furthermore, we used numerical simulations to investigate the effects of heterogeneity as well as rock and fracture properties on spatial distribution on nanoparticles in the porous media. We successfully synthesized paramagnetic nanoparticles with a core/shell structure with size of 60 nm–70 nm. The hysteresis loops obtained from the magnetic measurements demonstrate magnetic stability of the nanoparticles at both surface and reservoir temperatures. The magnetic nanoparticles provided high sensitivity when used as contrast agents in magnetic susceptibility measurements of carbonate and organic shale samples. The relative enhancement of the volume susceptibility depends on the minerals present within the formation, concentration of the nanoparticle solution, and the magnetic composition of the proppants. The results of the numerical simulations confirmed the effectiveness of using nanoparticles as contrast agents in highlight fractures and, hence, the location of the proppants. We have demonstrated in the synthetic examples that the nanoparticle concentration in hydraulic fractures is significantly higher than that in the surrounding porous rock in the case of low permeability formations, suggesting that hydraulic fractures can be clearly differentiated from the surrounding formations. We have thus illustrated from the experimental and numerical methods that the superparamagnetic nanoparticles which are mainly concentrated in the fractures can be used as contrast agents mixed with the proppants to highlight the fractures and detect the location of proppants. The prospect of injecting magnetic nanoparticles as contrasting agents along with propping agents during fracture treatment is promising for the accurate monitoring and tracking of propping agent. More developments on this approach will lead to improvement in the determination of the hydraulic-fracture geometry, which is of great value in designing hydraulic fracture treatments.
Abstract Acid treatment is a common stimulation technique for calcite-rich reservoirs. Retarded acid systems such as acid-inoil emulsions are typically used to minimize wellbore damage and long-distance propagation of acids from the wellbore. However, the stability of these emulsions under harsh reservoir conditions is still a challenge. This study investigates a novel, robust acid carrier system using silica nanoparticles for acid treatment of calcite-rich shales. First, highly hydrophobic silica nanoparticles were blended with concentrated acid solutions (0.5-15 wt%) to form acid-in-air powders or microencapsulated acids (MEA). The MEA were then placed in an unpropped fractured core system, and fracture closure was simulated by increasing the overburden pressure. It resulted in the mechanical crushing of the MEA and release of the acid. The conductivity of the cores before and after the MEA treatment was measured. Finally, the surface etching on the fracture face due to acid was quantified by measuring the surface roughness using an optical profilometer. Qualitative characterization was performed using optical microscopy. The mixing of highly hydrophobic silica nanoparticles (NP) with acids under high shear rates resulted in the formation of microencapsulated acid (MEA) by self-assembly of the NP at the water-air interface. These MEA particles were found to be robust encapsulating agents for acids where the release could be triggered via mechanical crushing. The fracture conductivity experiments showed that these MEA could drastically improve (up to 40 times) the permeability of the unpropped fractures by creating concentration-dependent, non-uniform localized surface etchings. Introduction Traditionally, natural gas production of the United States came from conventional oil and gas wells. However, over the last decade, the combined use of multi-stage hydraulic fracturing (HF) and horizontal drilling has unlocked the vast potential of the gas-bearing shale of North America. Prior to these technologies, the production from these shale basins was not considered economically viable due to their low natural permeability (μD to nD). HF leads to the formation of large interconnected fracture network which significantly increases the well-reservoir contact area leading to enhanced well productivity. Typical HF treatment involves the injection of either slick-water (water with friction-reducing chemicals) or viscous polymeric solutions resulting in the formation of long-narrow or short-wide fractures, respectively. These fracturing fluids are typically injected with solid proppant particles to keep the fractures propped even after the fracture closure. Clearly, the optimal proppant placement is a key for maintaining maximum fracture conductivity. The most commonly used proppants are sand (density: 2.65 gm/ cm3) which are economically available in large quantities. However, there are several technical challenges associated with using proppants in achieving optimal fracture stimulation during field applications. First, the proppants have a tendency to settle down in the near-wellbore region due to the large density contrast with the carrier fluid (Tong et al., 2018). It results in poor reservoir connectivity and unpropped fractures away from the wellbore (Kern et al., 1959; Warpinski et al., 2009). Second, HF typically results in the opening of naturally cemented micro-fractures (μF) or can induce formation/ reactivation of μF connected to the primary fracture (Taleghani et al., 2014; Warpinski et al., 2005). Due to their thinner apertures and distance from the well bore, these microfractures remain unpropped. These unpropped μF can act as capillary traps for fracturing fluids which impedes hydrocarbon flow to primary fracture during production (Taleghani et al., 2013).
Summary Viscoelastic surfactants (VESs) have been used for acid diversion and fracturing fluids. VESs were introduced because they are less damaging than polymers. VESs’ high cost, low thermal stability, and incompatibility with several additives (e.g., corrosion inhibitors) limit their use. The goal of this study is to investigate the interaction of VES micelles with different nanoparticle shapes to reduce VES loadings and enhance their thermal stability. This work examined spherical and rod-shaped nanoparticles of silica and iron oxides. The effects of particle size, shape, and surface charge on a zwitterionic VES micellization were conducted. The physical properties were measured using zeta-potential, dynamic light scattering (DLS), and transmission electron microscopy (TEM). The rheological performances of VES solutions were evaluated at 280 and 350°F using a high-pressure/high-temperature rotational rheometer. The proppant-carrying capacity of the fracturing fluids was evaluated using a high-pressure/high-temperature see-through cell and dynamic oscillatory viscometer. The fluid loss and formation damage were determined using corefloods and computed-tomography scans. The interaction between nanoparticles and VES is strongly dependent on the VES concentration, temperature, nanoparticle characteristics, and concentration. The spherical particles at 7-lbm/1,000 gal loading extended the VES-based-fluid thermal stability at VES loading of 4 wt% up to 350°F. The nanorods effectively enhanced and extended the thermal-stability range of the VES system at VES concentration of only 2 wt%. Both particle shapes performed similarly at 4 wt% VES and 280°F. The addition of silica nanorods extended the thermal stability of the 4 wt% VES aqueous fluid, which resulted in an apparent viscosity of 200 cp for 2 hours. The addition of rod-shaped particles enhanced the micelle to micelle entanglement, especially at VES loading of 2 wt%. The use of nanoparticles enhanced the micelle/micelle networking, boosting the fluid-storage modulus and enhancing the proppant-carrying capacity. The addition of nanoparticles to the VES lowered its fluid-loss rate and minimized formation damage caused by VES-fluid invasion. This research gives guidelines to synthesize nanoparticles to accommodate the chemistry of surfactants for higher-temperature applications. It highlights the importance of the selected nanoparticles on the rheological performance of VES.
Bose, Charles C (The University of Kansas, Lawrence, KS) | Alshatti AIR, Bader (The University of Kansas, Lawrence, KS) | Swarts, Levi (The University of Kansas, Lawrence, KS) | Gupta, Aadish (The University of Kansas, Lawrence, KS) | Barati, Reza (The University of Kansas, Lawrence, KS)
Abstract Guar-based fluids are commonly used as fracturing fluids to form a filter cake, propagate the fracture and carry proppants during a typical hydraulic fracturing job. High viscosity during injection and degradation afterwards are the characteristics of a high quality fracturing fluid that can maintain a highly conductive fracture during production. In order to achieve a conductive fracture, cross-linkers and breakers are added to the fluid. Filter cakes form on the faces of the fracture during injection causing a major pressure drop between the fracture and the reservoir during the production. Degradation of filter cakes formed on fracture faces has been accomplished using chemical breakers Enzymes and oxidizers are the two main classes of breakers. Enzyme breakers have many advantages over chemical oxidizers: they are cheap, are not consumed during their catalytic reaction with guar, react only with the polymer, are environmentally benign, easy to handle and do not damage wellhead equipment. Different methods of injecting high concentration breakers are still not capable of degrading the residues left after the fracturing jobs. Permeability reduction of proppant pack due to gel residues, width loss caused by the unbroken gel on fracture face and length loss caused by incomplete degradation of filter cake near the tip of the fractures have been previously reported. It has been previously proven that polyethylenimine-dextran sulfate (PEI-DS) nanoparticles can delay the release of enzymes which reduce the viscosity of cross linked guar. This delayed release can be advantageous in order to inject higher concentrations of enzymes by encapsulating the enzyme inside nanoparticles. However, performance of these nanoparticles in reaction with high concentration filter cakes has not been studied yet. The main objective of this work is to study the feasibility of using polyelectrolyte complex nanoparticles as enzyme breaker carriers and fluid loss additives to be used for hydraulic fracturing applications. Specifically, the fluid loss prevention and clean-up capabilities of the nanoparticle system for fractures propagated in tight formations are studied. Static fluid loss tests showed a significant reduction, caused by PEC nanoparticles, in both fluid loss coefficients and fluid loss volumes of tight core plugs with permeability values within the 0.01-0.1 mD range. Fracture conductivity tests, both fluid loss and clean-up, were conducted using HPG gel, HPG gel mixed with enzyme, and HPG gel mixed with enzyme-loaded nanoparticle systems and the results were compared with the baseline conductivity of the system. Significant improvement in the retained conductivity of the proppant pack was observed using the enzyme-loaded nanoparticle system.
Abstract This work presents new surface modified nanoparticles (SMN) that act as internal breakers for viscoelastic surfactant (VES) based fluids. Breaking profile is a key performance feature of a fracturing fluid. In addition to providing greater application latitude at high temperatures, the proposed solution is suited for gas wells or where there is less likelihood of encountering formation crude oil, which could also act as breaker for VES fluids. The SMNs were prepared by organically modifying nanoparticles with specific surface capping agents that have functional groups with the ability to bind on to their surfaces by chemical or physical interactions. The base VES fluid was prepared from a mixture of sea water, ionic strength agents and a viscoelastic surfactant formulation. Varying amounts of SMNs were added to the base fluid and mixed vigorously to form a homogeneously dispersed fluid. The viscosities of the base fluid without SMNs and with varying amount of SMNs were monitored over time at fixed temperature to observe the breaking profile. The base fluid consisting of VES dispersed in sea water with ionic strength agent exhibits stable viscosity for prolonged times. Compared to base fluid, addition of bare nanoparticles marginally improves the fluid's viscosity, although, the fluid does not break down to very low viscosity within desired time for convenient flowback operations. Slow viscosity drop is ideal from a fracturing fluid point of view that helps in efficiently placing the proppants inside of created fractures and eventual fluid cleanup. However, without the organically modified nanoparticles, the viscosity is too stable causing the post fracturing cleanup to be too slow. With the SMN the viscosity drop could be controlled and achieved in relatively shorter time. Further, with these breaker control over breaking time is also achievable. The SMN internal breakers interact with the worm like micelles and disrupt the gel formed by these elongated micellar structures. The surface modified nanoparticles with a functional capping agent alters the way the nanoparticles interact with the wormlike micelles from electrostatic interactions to hydrophobic-hydrophobic interactions. This change provides an efficient mechanism for breaking the VES base fluids in absence of any external breaker with high temperature latitude.