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.

Summary Proppants are solid particles with specific mechanical strength that are widely used in hydraulic-fracturing operations. Their main purpose is to keep fractures open and increase well production. They can be naturally occurring sand grains or synthetic ceramic proppants. The acid resistance of fracturing proppants is an important property because acids are used during the hydraulic-fracturing process to remove the scale and clays that affect fracture conductivity. These acids affect proppants that are already present in the fracture, as well. Industry measures acid solubility of proppants according to the API RP 19C (2008)/ISO 13503-2 (2006) standard. This measurement produces a solubility number, but gives no guidance on the expected final effect of acid dissolution on the mechanical performance of tested proppants or on how acid-solubility values vary as a function of time, temperature, and dynamic conditions. This study investigates factors affecting the interactions of regular mud acid [hydrofluoric acid (HF)/hydrochloric acid (HCl) = 3:12] with sand and clay-based proppants under downhole conditions. Experiments were conducted by use of an aging cell at temperatures up to 300°F. The effects of varying temperatures, soaking times, and static and dynamic conditions were examined. The supernatant of solubility tests was analyzed with fluorine nuclear magnetic resonance (19F-NMR) to identify the reaction products. Total aluminum, iron, silicon, titanium, and calcium concentrations were measured by inductively coupled plasma optical-emission spectroscopy (ICP-OES). A Zeiss Axiophot microscope was used to acquire images for the proppant particles to study particle shape and effect of acid solubility. Proppants were then analyzed by X-ray fluorescence (XRF) and X-ray diffraction (XRD). After the solubility tests, the proppants and the residual solids were dried and analyzed by use of scanning-electron microscopes (SEMs) with energy dispersive X-ray spectroscopy (EDS) capabilities. Effects of acid dissolution on mechanical performance of the proppants were also tested through use of an automated load frame. The results show that sand proppants are readily soluble in regular mud acid, with a maximum recorded solubility of 10 wt%. The amount dissolved increases with temperature, soaking time, and dynamic conditions. Clay-based proppants are also soluble in mud acid, with much higher acid solubility than that seen in sand proppants. The proppant packs show more compaction for clay-based proppants than for sand proppants before and after acid exposure. Understanding the effects of acid on natural and synthetic proppants will improve production by promoting the design of acidizing regimens used during hydraulic-fracturing operations.

Crude oil and natural gas can carry various high-impurity products which are inherently corrosive, such as, carbon dioxide (CO2) and hydrogen sulfide (H2S). These impurities increase operational safety risk and can be detrimental to production, both in terms of equipment damage and permeability impairment caused by scale deposition. Problems with iron sulfide scale occur when H2S comes in contact with spent acid solutions containing dissolved iron ions. While dissolution of pipe and iron bearing core materials in H2S solutions is known to result in FeS scale deposition, the reactivity of iron containing proppant material under sour conditions is poorly understood and documented. The present study evaluates and compares dissolution kinetics of iron bearing formation and ceramic proppants, which were derived from multiple sources of bauxite minerals, in H2S acid solution in order to evaluate their relative contributions to iron sulfide scale deposition. The study uses X-ray diffraction (XRD) and inductively-coupled plasma optical emission spectroscopy (ICP-OES) analysis to qualify Fe containing crystallite forms and quantify dissolution and scale build up reaction kinetics. Scanning Electron Microscopy (SEM) is used to evaluate surface morphology changes associated with iron dissolution and iron sulfide scale deposition. Finally, reactivity of all tested materials is compared based on their initial iron concentration and relative dissolution affinity.

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Gulf of Mexico Continental Shelf and Deepwater formations represent a harsh environment which causes difficulty predicting operational requirements for proppants using traditional methods. Common formation conditions are very high closure stresses approaching 20,000 psi and temperatures varying from 220°F and upwards, nearing 500°F, such as in the Lower Wilcox Formation on the continental shelf. Deepwater wells present economic investment for investors several orders of magnitude larger than onshore conventional and unconventional plays common in current land assets. Operators therefore place a great deal of focus on the design of the frac pack, completion tools, production and field development. Required qualification and understanding of proppant performance at these conditions far exceeds that needed for today's extensive shale market. Understanding the proppant behavior that brings economic value to these applications is difficult as current API/ISO performance measurements do not apply under these extreme conditions. Measurement artifacts due to limitations in laboratory materials, highly integrated measurement environment, apparatus limitation or statistical variability in proppant performance are common. New proposed protocol individually examines loss mechanism as a function of mechanical, thermal and chemical forces at high-temperature and high-pressure conditions. Integration of these proposed protocols with conventional testing allows better understanding of root causes of proppant performance losses. Laboratory measurements of proppants permit defining a boundary that separates stable, predictable performance from variable, unreliable performance. Closure stress, temperature, and several degradation mechanisms, such as cyclic stress and corrosion attack, influence the position of this boundary with respect to the mechanical strength of the proppant. Results show that commercially available high strength proppants exhibit a statistically proven variable performance when used under high-temperature, high-pressure conductions common to Deepwater conditions. Employing materials operating within a predictable performance regime is both an engineering and economic design decision for any fracturing application. Through independent evaluation of the mechanical, thermal, and chemical forces acting upon materials in the application, optimized solutions are possible that permit extracting value and stable performance from the well.