Brice Y. Kim and I. Yucel Akkutlu, Texas A&M University, and Vladimir Martysevich and Ronald G. Dusterhoft, Halliburton Summary The stress-dependent permeabilities of split shale core plugs from Eagle Ford, Bakken, and Barnett Formation samples are investigated in the presence of microproppants. An analytical permeability model is developed for the investigation, including the interactions between the fracture walls and monolayer microproppants under stress. The model is then used to analyze a series of pressure-pulsedecay measurements of the propped shale samples in the laboratory. The analysis provides the propped-fracture permeability of the samples and predicts a parameter related to the quality of the proppant areal distribution in the fracture. The proppant-placement quality can be used as a measure of success of the delivery of proppants into microfractures and to design stimulation experiments in the laboratory. Introduction Unconventional-oil/gas resources, such as tight gas/oil and resource shale, have low porosity and ultralow permeability. Creating a well-connected complex fracture network is a key component of increasing the permeability and accelerating production. The early era of hydraulic fracturing horizontal wells in unconventional formations was concerned with achieving long fractures with multistage treatments with large cluster spacing. However, recent trends in this type of well completion and stimulation involve fractures that are created in narrower clusters in much closer spacing, targeting larger surface areas. It is argued that the practice of hydraulic fracturing with narrow clusters in close spacing along a lateral wellbore creates fractures with significantly reduced sizes, but in a complex network (Rassenfoss 2017). The creation of a network of fractures includes major operational issues.
Fracture stimulation of horizontal wells in unconventional gas-or oil-producing reservoirs by placing a large number of transverse or pseudo transverse fractures in reference to the wellbore orientation is usually necessary to help maximize hydrocarbon recovery in complex environments. Although economic completion and multistage fracture stimulation of unconventional reservoir using horizontal wells dates back to mid-2002, particularly in North America, it has been gradually modified and improved through extensive trial and error processes to improve the stimulation effectiveness in unconventional reservoir productivity. However, the trial and error process is not often effective nor a recommended practice in the refracturing processes where differential areal depletion is present. This paper demonstrates the effect of differential depletion normally present in existing unconventional producing reservoirs and how to optimize additional fracture(s) placement during refracturing processes or infill well placement to help maximize hydrocarbon recovery. In line with the economic considerations and the massive implementation of completion activities, the industry has often applied the trial and error process in the unconventional reservoir. Initial completions involve variations of (but not limited to): pumping rate, total lateral length, spacing and number of perforation clusters, perforations per cluster, lateral length of treated stages, length of fractures generated, proppant and stimulation fluid volumes per stage, and lateral well spacing. The initial completion strategy was often intended to prevent or minimize the negative effect of interferences or non-effective completion techniques which could result in the use of longer perforation clusters, longer fracture stage spacing, or conservative completions. Additionally, if the completion design is not effective in maximizing the fracture initiation points per stimulation stage, a significant bypass of hydrocarbon reserves between the fractures or well laterals can happen. To produce the additional bypassed hydrocarbon reserves, an engineered process to refracture existing wells should be implemented if they are economically justified.
In a vertically transverse isotropic (VTI) medium, accurate prediction of the vertical and horizontal Young’s moduli (E) and Poisson’s ratios (ν) is crucial to predicting minimum horizontal stress (σhmin) and hence selecting drilling mud, cement weights, and perforation locations. Fully characterizing the geomechanical properties of VTI shale requires five independent stiffness coefficients. In a vertical well, two of them are directly calculated from the velocity of the vertically propagating compressional waves (P-waves) and shear waves (S-waves), whereas a third is estimated from the Stoneley-wave velocity. To obtain the last two stiffness coefficients, an empirical model must be used. This study integrates laboratory mechanical and sonic measurements to evaluate the ANNIE and modified- ANNIE models and extend the dynamic-to-static conversion equations. The ANNIE model is a three-parameter empirical model proposed by Schoenberg et al. (1996) to interpret anisotropic stiffness coefficients.
Laboratory static and dynamic geomechanical experiments were applied to multiple core plugs extracted at different depths from a target shale play. Using a laboratory ultrasonic scanner, velocities were measured in different directions to obtain the five stiffness coefficients. To compare the performance of the two empirical models, three stiffness coefficients were then applied along with the ANNIE or modified-ANNIE models for estimating the dynamic Young’s modulus and Poisson’s ratio. The static elastic moduli were measured using triaxial compression experiments; horizontal and vertical core plugs were tested to account for anisotropy.
Static and dynamic results illustrated that horizontal Young’s moduli were predominantly higher than vertical Young’s moduli, which suggested a horizontal layered structure. Vertical Poisson’s ratios can be greater or smaller than horizontal Poisson’s ratios, which is consistent with the prediction of the modified-ANNIE model. Conversely, the ANNIE model always predicts ν (vertical) ≥ ν (horizontal). Static and dynamic data illustrated that the anisotropic σhmin (minimum horizontal stress) was predominantly higher than the isotropic σhmin. This implied that using an isotropic model to predict laminated shale will underestimateσhmin. The elastic moduli measured from the dynamic method were consistently higher than those measured from the static method. The dynamic and static data were used to fit the widely used dynamic-to-static conversion equations: the Canady (2011) and Morales and Marcinew (1993) equations. The Canady (2011) equation was extended to the “very hard” (greater than 70-GPa or 10.2-Mpsi Young’s modulus) regime, whereas the Morales and Marcinew (1993) equation was extended to the regime of porosity less than 10%. Mpsi¼1,000 psi. Finally, the results of σhmin predicted by the isotropic and two anisotropic models (ANNIE and modified-ANNIE) were compared with the values of σhmin calculated using full ultrasonic data measured in the laboratory, showing that modified-ANNIE improved the prediction by solving the stress-underestimation issue of the ANNIE and isotropic models.
This paper describes the stress-dependent permeability of split shale core plugs from Eagle Ford, Bakken, and Barnett formation samples studied in presence of microproppants in microcracks. An analytical permeability model is developed, including the interaction between the fracture walls and monolayer microproppants under stress. The model is then used to analyze a series of pressure pulse decay measurements of the propped shale samples in the laboratory. The analysis provides the propped fracture permeability of the samples and predicts a parameter related to the quality of the proppant areal distribution in the fracture. The proppant placement quality can be used as a measure of success of the delivery of proppants into the fractures and to design stimulation in the laboratory.
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 (
In a vertically transverse isotropic (VTI) medium, accurate prediction of the vertical and horizontal Young's moduli (E) and Poisson's ratios (?) is crucial to predicting minimum horizontal stress (shmin) and hence selecting drilling mud, cement weights, and perforation locations. Fully characterizing geomechanical properties of VTI shale requires five independent stiffness coefficients: C33, C44, C66, C11, and C13. In a vertical well, C33 and C44 are directly calculated from the velocity of the vertically propagating P- and S- waves, while C66 is estimated from the Stoneley wave velocity. To obtain C11 and C13, an empirical model must be employed. This study integrates laboratory mechanical and sonic measurements to evaluate the ANNIE and modified-ANNIE models and extend the dynamic-to-static conversion equation.
Laboratory static and dynamic geomechanical methods were applied to multiple core materials extracted at different depths from a target shale play. The dynamic elastic moduli were measured using a laboratory sonic scanner; velocities were measured in different directions to obtain C33, C44, C11, C66, and C13. The dynamic data were then applied in the ANNIE and modified-ANNIE models for estimating the dynamic elastic moduli, including dynamic Young's modulus and Poisson's ratio. The static elastic moduli were measured using axial compression experiments; horizontal and vertical core plugs were tested to account for anisotropy.
Static and dynamic results illustrated horizontal Young's moduli were predominantly higher than vertical Young's moduli, which suggested a horizontal layered structure. Vertical Poisson's ratios can be greater or smaller than horizontal Poisson's ratios, which is consistent with the prediction of the modified-ANNIE model. Conversely, the ANNIE model always predicts ?(vert) = ?(horz). Static and dynamic data illustrated the anisotropic shmin was predominantly higher than the isotropic shmin. This implied that using an isotropic model to predict laminated shale will underestimate shmin. It was noticed that the static Young's modulus increased with decreasing porosity for the target interval. The elastic moduli measured from the dynamic method were consistently higher than those measured from the static method. The dynamic and static data were used to fit the widely-used dynamic-to-static conversion equations—the Canady and Morales equations. The Canady equation was extended to the "very hard" (greater than 70 GPa Young's modulus) regime, while the Morales equation was extended to the regime of porosity < 10%. Finally, shmin predicted by different models was compared with the measurements, showing that modified-ANNIE improved the prediction by solving the stress underestimation issue of the ANNIE and isotropic models.
The porosity and geological texture of tight oil and shale gas samples have significant effects on reservoir production and oil/gas recovery. Classical measurements, such as porosity logs, alone cannot accurately predict the amount of oil and gas storage and final recovery ability because of aspects, such as the rough resolution of the technique and indirect measurement methods; therefore, the corresponding calibration is a critical step. Additionally, the presence of nanopores and micropores within organic matter or on the boundaries between mineral components affect formation properties, and logs cannot resolve at this scale. This paper presents the internal structure imaging and analysis studies of a series of Vaca Muerta Shale samples from different depths and basin locations. Methods include the nanoscale scanning electron microscope (SEM) imaging, pore size distribution analysis, various imaging based simulations and calculations, and field logging data comparisons. As stated in the literature, the Vaca Muerta Shale is a highly promising continuous tight oil and shale gas reservoir and is an important petroleum source bed for oil production.
The results indicate that the trend of petrophysical properties, such as porosity as a function of depth, is consistent with logs; but, lab measurements suggest a relative shift of log values, which demonstrates the importance of lab calibration. The internal structures of samples have a stable trend as the depth increases in the way most pores exist within the organic matter at deep depths, while the position of pores gradually moves to the boundaries of mineral components at shallow depths. The shape of the pores varies as the depth increases. This is one of the first papers discussing combining novel digital rock imaging techniques with traditional logging methods. Efficient and accurate digital rock studies can help provide a good calibration using logging analysis, which can eventually benefit reservoir evaluation and oil/gas production. Comparison between direct observations/image based calculations and logging data analysis provide explanations of changing trends of pore and organic matter. Other important petrophysical and geological properties, such as permeability, total organic carbon (TOC), and so on, through lab measurements are also discussed. This study provides insight into the development of predictive stratigraphic framework and a conceptual reservoir model for the Vaca Muerta interval and also helps improve the understanding of its storage and flow capacity.
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 stress-increase process. It has important applications, which help sustain production with adequate fracture conductivity in deep reservoirs (e.g., the Haynesville shale).
Digital rock analysis is very efficient and accurate for evaluating matrix, porosity, and permeability in unconventional reservoirs, especially shales. It has been recognized as one of the most promising emerging technologies in oil and gas development, providing an alternative method to solve problems that are typically difficult to analyze using traditional laboratory techniques. In this study, high-resolution data are acquired from samples with sandstone, carbonate, and shale lithologies using micro- and nano-computed tomography (CT) scanning and a focused ion beam/scanning electron microscope (FIB/SEM), and the pore throat space is extracted using an imaging segmentation process. The extracted pore throat data are statistically analyzed through a digital rock workflow that develops a skeleton network of pore throat channels, generating a distance map of the pore throat channels and values of pore surface area. These data are then used to statistically evaluate pore size and pore throat size distribution, network connectivity, effective porosity, and permeability. By comparing the statistical data for each lithology, useful differences are noted that can possibly be correlated to pore-system characteristics that affect recovery efficiency. Pore-systems are important because they control both the volume and flow characteristics of hydrocarbon, which are crucial to recovery efficiency. A lithologically distinct statistical evaluation is used to determine the representative elemental volume (REV) as based on the stable pore throat size trends using curve-fitting functions that are uniquely distinct for each lithology. These functions effectively act as a potential fingerprint for each distinctive lithology. Data are presented to determine a specific correlation between parameters for appropriate REV for certain rock types, and differences in conventional and unconventional reservoirs are discussed. Conclusions regarding the reservoir formations and oil/gas volume and flow capabilities are presented.
Transporting proppant deep into hydraulic fractures without settling is critical to success of hydraulic fracturing operations. The current capability to predict proppant transport for a given fracturing fluid is often limited to the power law model and Stokes equation without quantitative consideration of other important fluid property changes, such as elasticity caused by shear flow in the fracture. The goal of this study is to investigate the effect of shear flow on proppant settling over long time periods.
For this purpose, a multipass slot flow apparatus has been developed to mimic fracture flow. Unlike existing slot flow devices, the new apparatus is capable of running continuously and attaining a time scale more similar to a realistic fracturing treatment. The proppant transport behaviors of a variety of fracturing fluids, including linear and crosslinked gels, are investigated. For crosslinked gels, two types of crosslinkers possessing very different characteristics are examined. One uses borate ions, which react with polysaccharides to form a reversible and rehealing crosslinked gel. The other gel uses zirconium, which forms an irreversibly crosslinked gel with the same polymers. To probe the relative importance of elasticity and viscosity, samples with various viscosities and elasticities are formulated and their proppant suspending power is measured. It is demonstrated that these different fracturing fluids show dramatically different static and dynamic proppant suspending behavior, which is correlated to their rheological properties, including yield stress, viscosity, and elasticity. These findings can provide valuable guidance in terms of optimizing fracture fluid design to maximize proppant transport properties.