Effective proppant placement during hydraulic fracturing is essential to obtain maximum stimulation effectiveness. Understanding proppant placement requires the understanding of the time and space dependent dynamics of proppant motion in fluids, which include the phenomena of proppant transport, bridging, settling, and resuspension. This paper proposes a laboratory test method that can be used to investigate any aspect of proppant dynamics in a variety of channel configurations and fracturing fluids. 3D printing technology is used to rapidly manufacture channel flow devices of various dimensions. After a 3D printer is available, such manufacturing is extremely inexpensive with rapid turn-around times. These channels, in conjunction with laboratory scale pumps and blenders, are used to investigate proppant transport and bridging, settling, and resuspension in various fracturing fluids. Several different channel configurations, ranging from uniform width to uniform tapered, are used to investigate the dynamics of small and large diameter proppants with fluids ranging from water to linear gels. The results from these experiments are compared with numerical models for validation, and in some cases, calibration of model inputs, that can ultimately lead to improved fracturing treatment design and understanding. In addition, the paper provides a comparison to existing data (Patankar et al. 2002) to validate settling and resuspension models.

Two shale gas rock samples, from a Middle East shale gas play and the Eagle Ford shale play, respectively, were scanned using a nanometer-scale focused ion beam-scanning electron microscope (FIB-SEM). The geometrical properties were extracted and compared. The high-resolution image data were then processed and used as boundary conditions in the pore-scale GPU-accelerated lattice Boltzmann simulator (GALBS) for permeability simulation. The GALBS is based on the lattice Boltzmann (LB) method and optimized by graphics processing unit (GPU) parallel computing. Image processing showed that although the intrakerogen pores in the Eagle Ford sample had larger pore volumes compared to those in the Middle East sample, their morphologies were more laminar, which leads to higher friction to fluid flow and consequently gives rise to lower macroscopic permeability. GALBS simulations confirmed that the permeability was at the nanodarcy (nd) level in the Eagle Ford sample, while it was at the microdarcy (μd) level in the Middle East sample. Furthermore, anisotropy in the permeability tensor was observed in both shale samples. The computing speed of the GALBS is more than 1,000 times faster than the serial code and more than 10 times faster than the parallel code run on a standalone CPU, which suggests that many more samples can be analyzed given the same processing time. The combination of high-resolution imaging methods and high-performance parallel computing is a powerful tool for studying microscopic processes and upscaling. It provides for a more accurate estimation of the total stored gas and is helpful in the optimization of hydraulic fracturing treatments, which are aimed at connecting as many isolated intrakerogen pores as possible. The method presented in this study enables more accurate characterization of microscopic geometries and faster upscale transport properties, illustrating that unconventional energy recovery requires unconventional solutions.

A fracture/proppant system is used to mimic the interaction between the rock matrix and proppants during the process of fracture closing attributed to pore-pressure reduction during hydrocarbon production. Effects of rock type and bedding-plane direction are investigated. High-strength sintered bauxite proppants are placed in hydraulic fractures in sandstone and shale rock. There are two bedding-plane directions in shale rock: One is 90 , which is perpendicular to the fracture, whereas the other is 0 , which is parallel to the fracture. Increasing mechanical loading is imposed to close the fracture. Micrometer-scale X-ray tomography is used to visualize the internal structure. Cutting-edge image-processing methods are applied to extract patterns of both the fracture and matrix. A pore-scale lattice Boltzmann simulator, optimized with graphics-processing-unit parallel computing, is used to simulate the permeability tensor inside the fracture. Significant proppant embedment is observed in the sandstone rock when the effective stress is increased to 4,200 psi. Consequently, fracture porosity is reduced by nearly 70%, and permeability is reduced by two orders of magnitude. Embedded proppants are unable to create microscopic fractures on the matrix surface because of the low bonding strength between grains. In the shale rock with 90 bedding planes, when the effective stress is increased to 3,000 psi, significant microscopic fractures on the matrix surface are created because the lamination structure of the matrix is opened. In the shale rock with 0 bedding planes, noticeable microscopic fractures on the matrix surface are not observed until the effective stress is increased to 6,990 psi. Proppant embedment is insignificant because of the high bonding strength between fine grains. Significant anisotropy in the permeability tensor is observed during all experiments. This study is the first to use cutting-edge imaging and modeling methods to quantitatively study the interaction between proppants and the rock matrix during the stressincrease process. It has important applications, which help sustain production with adequate fracture conductivity in deep reservoirs (e.g., the Haynesville shale). Laboratory Materials and ApparatusAs illustrated in Fig. 1a, a cylindrical core plug (1-in. diameter and 2-in. length) was cut into two identical halves. The space between the two halves is the primary propped hydraulic fracture and hereafter is referred to as the primary fracture, in which 20-to 40-mesh high-strength sintered bauxite proppants were uniformly placed to form a monolayer. All the materials were retained in place by a cylindrical sleeve. Uniaxial mechanical stress was imposed to close the primary fracture (Fig. 1b) to mimic the

Creating multiple zone stimulations in complex reservoirs presents unique challenges for the completion engineer. Effectively stimulating each individual pay interval using separate fracturing treatments can be costly and time consuming. Historically, efforts to stimulate multiple zones usually consisted of casing fracs with limited entry perforating and using sand plugs to separate zones, or tubing fracs with retrievable bridge plugs and packers. The challenge was to rethink the approach to this technology and develop more cost effective and efficient solutions. Those efforts have resulted in a new approach called pinpoint stimulation. New pinpoint stimulation methods have resulted in reduced cycle time for operators. This means doing multiple service operations in a single trip to the well. If performed individually, perforating, fracturing, setting isolation plugs, and cleaning out the wellbore for each interval can add days or weeks to a completion, delaying production-to-sales and increasing overall costs. Now, we perforate, fracture stimulate, and clean out with a single trip to the wellsite. Each treatment stage is customized for the intervals treated and many more intervals can be stimulated economically. Pinpoint multistage fracturing is available in 16 different processes for many types of well completions. In this paper, we present different techniques for a wide variety of applications and provide actual treatment data and results including recent case histories from Russia. Introduction Since the first commercial hydraulic fracturing treatment was performed by Halliburton in Velma, Oklahoma in March 1949, the industry has relied on multistage fracturing to help maximize asset value. Selectively stimulating individual intervals in the wellbore can help to keep operating costs low, reduce time to initiation of production, and improve ultimate recovery. One of the first experimental fracture treatments on record is reported to have been a four-stage pinpoint stimulation in July 1947 in the Kansas portion of the Hugoton field, which targeted four limestone gas pays at depths ranging from 2,340 ft (713 m) to 2,580 ft (786 m). That stimulation job was conducted in four separate hydraulic fracturing treatments (stages), each of which involved pumping 1,000 gal (3785 L) of napalm (thickened gasoline) through jointed tubing equipped with a cup-type straddle packer, followed by 2,000 gal (7570 L) of gasoline with 1% gel breaker. Selectively fracturing individual zones with a series of treatments was the only option possible at the time because of the equipment limitations. The available equipment was not capable of pumping the high rates, volumes, and pressures necessary to stimulate large sections of the wellbore. That began to change in the 1950s as the introduction of better casing and tubular products, more powerful pumps, and more capable wellsite equipment combined to enable operators to reach deeper, larger oil-and gas-bearing strata. By the mid-1960s, the primary method used to stimulate gas wells in the Hugoton field was to hydraulically fracture long sections of the wellbore, frequently encompassing several intervals in a single treatment, by pumping large volumes of low-cost, water-base fluids at very high rates. This reflected an industry-wide trend toward large, high-volume fracture treatments targeting several intervals in the wellbore and away from strategies allowing the selective treatment of individual intervals in a well.

Natural fractures widely exist in shale samples, and natural opening-mode fractures reactivate during stimulation and enhance efficiency by widening the treatment zone. The existence of natural fractures is very important to the stimulation treatment and will eventually benefit the shale gas/oil reservoir recovery. The effect of natural fractures on a shale mechanical property study will serve as the basis for the formation evaluation and the sweetspot selection on the hydraulic fracturing treatment. By combining conventional destructive mechanical tests and novel digital rock nondestructive analysis, important conclusions can be determined regarding the mechanical properties changing trend as a function of the fracture structure. The more complex the natural fracture structures, the less resistant the rock. This paper presents, in detail, the changing trend from various shale samples. Studies on the mechanical properties of Eagle Ford shale samples (e.g., Young's modulus, Poisson's ratio, etc.) are performed in a laboratory using a hydraulic load frame, and the core internal fractures are computed tomography (CT) scanned before and after the mechanical tests. The effect of natural fractures on the mechanical properties is analyzed through the testing data. The induced fractures are characterized in several Eagle Ford shale core plugs in terms of orientation, size, and width. Substantial image processing techniques are employed to analyze the three-dimensional (3D) rock microstructures. The statistical properties, such as the width, length, and the tortuosity of the main fractures, are obtained through image analysis. The volume of the fractures and the permeability on all x, y, and z directions on the central part of the core plug are calculated based on the 3D CT images as well. The small fractures can serve as the planes of weakness and reactivate during a hydraulic fracture treatment. This paper elaborates on the data interpretation and measurement correlation methods used to study natural fracture behavior as well as how this behavior affects mechanical tests, which can be very important in the field of geomechanics as well as formation stimulation research.