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Abstract In this case study, we apply a novel fracture imaging and interpretation workflow to take a systematic look at hydraulic fractures captured during thorugh fracture coring at the Hydraulic Fracturing Test Site (HFTS) in Midland Basin. Digital fracture maps rendered using high resolution 3D laser scans are analyzed for fracture morphology and roughness. Analysis of hydraulic fracture faces show that the roughness varies systematically in clusters with average cluster separation of approximately 20' along the core. While isolated smooth hydraulic fractures are observed in the dataset, very rough fractures are found to be accompanied by proximal smoother fractures. Roughness distribution also helps understand the effect of stresses on fracture distribution. Locally, fracture roughness seems to vary with fracture orientations indicating possible inter-fracture stress effects. At the scale of stage lengths however, we see evidence of inter-stage stress effects. We also observe fracture morphology being strongly driven by rock properties and changes in lithology. Identified proppant distribution along the cored interval is also correlated with roughness variations and we observe strong positive correlation between proppant concentrations and fracture roughness at the local scale. Finally, based on the observed distribution of hydraulic fracture properties, we propose a conceptual spatio-temporal model of fracture propagation which can help explain the hydraulic fracture roughness distribution and ties in other observations as well.
Summary Nanoscale porosity and permeability play important roles in the characterization of shale-gas reservoirs and predicting shale-gas-production behavior. The gas adsorption and stress effects are two crucial parameters that should be considered in shale rocks. Although stress-dependent porosity and permeability models have been introduced and applied to calculate effective porosity and permeability, the adsorption effect specified as pore volume (PV) occupied by adsorbate is not properly accounted. Generally, gas adsorption results in significant reduction of nanoscale porosity and permeability in shale-gas reservoirs because the PV is occupied by layers of adsorbed-gas molecules. In this paper, correlations of effective porosity and permeability with the consideration of combining effects of gas adsorption and stress are developed for shale. For the adsorption effect, methane-adsorption capacity of shale rocks is measured on five shale-core samples in the laboratory by use of the gravimetric method. Methane-adsorption capacity is evaluated through performing regression analysis on Gibbs adsorption data from experimental measurements by use of the modified Dubinin-Astakhov (D-A) equation (Sakurovs et al. 2007) under the supercritical condition, from which the density of adsorbate is found. In addition, the Gibbs adsorption data are converted to absolute adsorption data to determine the volume of adsorbate. Furthermore, the stress-dependent porosity and permeability are calculated by use of McKee correlations (McKee et al. 1988) with the experimentally measured constant pore compressibility by use of the nonadsorptive-gas-expansion method. The developed correlations illustrating the changes in porosity and permeability with pore pressure in shale are similar to those produced by the Shi and Durucan model (2005), which represents the decline of porosity and permeability with the increase of pore pressure in the coalbed. The tendency of porosity and permeability change is the inverse of the common stress-dependent regulation that porosity and permeability increase with the increase of pore pressure. Here, the gas-adsorption effect has a larger influence on PV than stress effect does, which is because more gas is attempting to adsorb on the surface of the matrix as pore pressure increases. Furthermore, the developed correlations are added into a numerical-simulation model at field scale, which successfully matches production data from a horizontal well with multistage hydraulic fractures in the Barnett Shale reservoir. The simulation results note that without considering the effect of PV occupied by adsorbed gas, characterization of reservoir properties and prediction of gas production by history matching cannot be performed reliably. The purpose of this study is to introduce a model to calculate the volume of the adsorbed phase through the adsorption isotherm and propose correlations of effective porosity and permeability in shale rocks, including the consideration of the effects of both gas adsorption and stress. In addition, practical application of the developed correlations to reservoir-simulation work might achieve an appropriate evaluation of effective porosity and permeability and provide an accurate estimation of gas production in shale-gas reservoirs.
Reliable estimation of formation tectonic stresses plays an important role in geomechanics and managing well-planning problems, where detailed knowledge of stress magnitudes and directions is needed for accurate prediction of wellbore stability, characterization of reservoir behavior, anisotropy analysis, etc. One of the prevalent methodologies for stress evaluation involves cross-dipole measurements followed by dispersion analysis at sonic frequencies. The crossover of the dipole dispersion curves indicates the presence of differential stresses around the wellbore. Fast and slow shear slownesses are split at low frequencies and determined by the far-field stresses. On the other hand, it is known that the depth of investigation at sonic frequencies is relatively far from where the largest variation of the stress-induced anisotropic formation slownesses exists which is near wellbore area.
As an alternative approach, this paper presents the importance of the ultrasonic azimuthal slowness measurements (microsonic) for characterizing stress effects in boreholes. The abilities of such measurements are numerically evaluated by simulating elastic waves propagating in formations subjected to triaxial stresses. Taking advantage of the short wavelength, the ultrasonic measurement is found to be highly sensitive to formation properties at shallow distances from the borehole wall and suitable for mapping stress-induced variations of compressional and shear slownesses around the wellbore. These slownesses are evaluated from simulated waveforms as a function of the azimuth around the borehole using a semblance processing algorithm.
Knowledge of tectonic stresses is required for key oilfield operations including well planning, drilling, wellbore stability analysis and enhanced production. One of the prevalent methods for characterizing tectonic stresses is to use borehole acoustic logging tools, such as wireline or Logging-While-Drilling (LWD) sonic tools. It is known that even in homogeneous and isotropic formations, the presence of a borehole disturbs the stress fields in the vicinity of the wellbore, alters elastic properties of surrounding formations, and, therefore, results in stress-induced acoustic anisotropy.
It is well known that tensile residual stresses from welding reduce the fatigue strength of welded joints. Fatigue design guidelines consider residual stress effects in the nominal stress approach by means of a mean stress correction. Fatigue enhancement factors for the manipulation of the design fatigue strength are provided in dependence of the residual stress conditions. However, these guidelines distinguish between “high”, “medium” and “low” tensile residual stresses resulting in different mean stress correction factors. Until today no reliable criteria is given to structural engineers which of these three residual stress groups “high”, “medium” or “low” apply to a given residual condition.
This work presents a model for the quantitative consideration of any residual stress value in fatigue design. The model was derived from fatigue testing of welded longitudinal stiffeners at different stress ratios and in different residual stress conditions. It considers cyclic residual stress relaxation and can be used for high and low strength construction steels. This work shows that the fatigue strength is a function of the effective mean stress under consideration of cyclically stabilized residual stresses and nominal load mean stresses.
It is commonly known that the fatigue strength of welded structures may be affected by load mean stresses. The current IIW recommendations for fatigue design of welded structures provide fatigue strength design values obtained at high tensile mean stresses, named FAT-classes (Hobbacher, 2009). These values can be used conservatively for all loading conditions but neglect the beneficial effect of lower mean stresses or compressive residual stresses. Residual stresses are rather covered by the simple approach of generally assuming high tensile residual stresses from manufacturing and mounting. Yet a more detailed consideration of residual stresses is possible only qualitatively. Designer must decide whether the structural detail of interest is covered by one of the three given residual stress groups “low”, “medium” or “high” tensile residual stresses. The measure for the classification of residual stresses is commonly the yield strength of the material which leads to some specific problems.
Abstract Induced fracture complexity maximization, in addition to the primary hydraulic fracture, to improve the recovery efficiency or productivity of gas or liquids in unconventional resource shale reservoirs has been accepted and fully implemented by the industry. As a result, stimulation fluids and/or completion strategies have been engineered to maximize induced fracture complexity in many unconventional reservoirs. In typical unconventional horizontal completions, induced fracture complexity is beneficial for the productivity of nanodarcy (nd) shales if conductivity is sustained in time, although induced fracture complexity may not be a requirement for all unconventional reservoirs, especially tight sands. In some unconventional reservoirs, operators have observed similar productivity in wells with predominantly planar fractures compared to wells that appear to have more complex fractures. This paper, supported by extensive reservoir simulations, aims to develop criteria for situations in which induced fracture complexity and sustained conductivity are required and when they are not. The simulations include a reservoir permeability range of 10 nd to 0.001 md and a fracture complexity conductivity of 1 to 5 md-ft with and without stress dependence. The simulation results show that the fracture complexity with a constant and sustained conductivity (no stress dependent) are generally important for reservoir permeabilities lower than 100 nd for gas and 500 nd for liquid-producing reservoirs, but this benefit is minimized when the induced or existing stresses negatively affect the fracture complexity conductivity. Based on these results, an optimized completion strategy is suggested to maximize the productivity or recovery factor (RF) in unconventional gas- and liquid-producing reservoirs.
Abstract Gas flow modelling in shale and tight gas reservoirs is still challenging mainly due to different pore-scale flow regimes present in micro- and nano-pores of these reservoirs. The effect of geomechanical stress also significantly affect the measurement and prediction of apparent matrix permeability. In this study, series of experiments were designed and performed on three shale samples to study the simultaneous effects of slippage and stress at five different pore pressures and four net stresses. The experimental data were used to obtain a general slip plot, which quantifies the effect of slippage on matrix permeability. Then, the stress effect was taken into account by modifying the average pore size and non-slip permeability at each net stress based on the experimental observations. It is found that the matrix non-slip permeability and average pore size follow an exponential behaviour when changing the net stress. These two relationships are then proposed to be incorporated into the corresponding slip flow model in order to capture the effects of slippage and stress at the same time. The validity of the proposed model was also investigated (using published data in the literature), which shows that the proposed technique is able to capture the intensity of permeability reduction and enhancement due to stress and slippage, respectively. The outcomes of this study increase our knowledge of rarefied flow dynamic inside micro- and nano-pores under confining stress, which is necessary for accurate predictions of the apparent matrix permeability in unconventional reservoirs.
Summary The current technique to produce shale oil is to use horizontal wells with multistage stimulation. However, the primary oil-recovery factor is only a few percent. The low oil recovery and abundance of shale reservoirs provide a huge potential for enhanced oil-recovery (EOR) process. Well productivity in shale oil-and-gas reservoirs primarily depends on the size of fracture network and the stimulated reservoir volume (SRV) that provides highly conductive conduits to communicate the matrix with the wellbore. The fracture complexity is critical to the well-production performance, and it also provides an avenue for injected fluids to displace the trapped oil. However, the disadvantage of gasflooding in fractured reservoirs is that injected fluids may break through to production wells by means of the fracture network. Therefore, a preferred method is to use cyclic gas injection to overcome this problem. In this paper, we use a numerical-simulation approach to evaluate the EOR potential in fractured shale-oil reservoirs by cyclic gas injection. Simulation results indicate that the stimulated fracture network contributes significantly to the well productivity by means of its large contact area with the matrix, which prominently enhances the macroscopic sweep efficiency in secondary cyclic gas injection. In our previous simulation work, the EOR potential was evaluated in hydraulic planar-traverse fractures without considering the propagation of a natural-fracture network. In this paper, we examine the effect of fracture networks on shale oilwell secondary-production performance. The impact of fracture spacing and stress-dependent fracture conductivity on the ultimate oil recovery is investigated. The results presented in this paper demonstrate that cyclic gas injection has EOR potential in shale-oil reservoirs. This paper focuses on evaluating the effect of fracture spacing, the size of the fracture network, fracture connectivity (uniform and nonuniform), and stress-dependent fracture-network conductivity on well-production performance of shale-oil reservoirs by secondary cyclic gas injection.
Abstract Induced fracture complexity or natural fracture contribution to the productivity or hydrocarbon recovery optimization of unconventional reservoirs is fully accepted in the industry but not properly quantified, especially for complex environments where the high induced stresses can affect their shortor long-term conductivity and benefit. With respect to an unconventional reservoir’s matrix permeability, induced fracture complexity or existing natural fracture conductivity can also be pressure-dependent, which will drastically affect well productivity if an operator does not properly consider permeability, complexity, and conductivity during the well-completion stage. If the pressure-dependent induced fracture complexity is packed as much as possible with small proppant or a microproppant system during the well-completion stage to assure its conductivity, the induced complexity will have a positive impact on well productivity; otherwise, only the stimulation fluid efficiency will be affected. Conversely, for existing pressure-dependent natural fractures, proper or limited packing is required to help minimize the negative impact of overpacking the open natural fractures and altering their original conductivity. Considering the different completion scenarios and inclusion of small proppants or a microproppant system in the stimulation process, this paper quantifies the inherent benefits of the pressure-dependent induced fracture complexity and pressure-dependent natural fractures by performing numerous reservoir simulations of unconventional gas reservoirs.
We have made various laboratory measurements on halite salt. Most of the effects of crystal defects and inter-crystal cracks on P-wave velocity can be removed after high pressure annealing. The temperature effect on seismic velocities of halite salt is dominant relative to the stress effect. We did not observe azimuthally anisotropy on the halite salt sample. We analyzed that the directional velocity variations are not indication systematic anisotropy, instead they are most likely caused by crystal-scale heterogeneity. No significant dispersion of seismic velocities is observed from the low frequency measurement.
Laboratory measurement data on rock physics properties of underground salt rocks are rare. Although salt rock cannot store petroleum itself, it is found that underground salt is often closely related to high productive petroleum reservoirs because creeping deformation of salt can be beneficial to formation of potential oil and gas traps. The dimensions of the underground salt can be significant. For accurate delineation of structures of the reservoirs associated with underground salt, we need more understanding of the seismic properties of underground salt.
The naturally formed single halite crystal has cubic shape and has cubic velocity anisotropy (Sun, 1994). After creeping deformation, the halite salt usually has polycrystal structure (Lebensoh, et al., 2003). Landrø et al. (2011) has observed moderate velocity anisotropy in the salt outcrop at Cardona, Catalonia in Spain. Since underground salt can occur in a wide range of depths and temperatures, in this study, we will first try to measure the stress and temperature effects on seismic velocities of halite salt, then will try to observe the existence of velocity anisotropy on the halite salt sample. Finally, low frequency measurement is conducted to test frequency dependency of seismic velocities.
A robust understanding of the thermal stress development due to injection of cold fluids is crucial when developing the Åsgard field on the Norwegian Continental Shelf (NCS) offshore Norway. To get a better and more direct estimation of the stress reduction, a series of triaxial tests under uniaxial strain control were conducted with cooling on reservoir core samples. The purpose of the testing program was to find elastic properties, thermal expansion coefficients and change in confining stress due to temperature reduction. The results show that the cooling related stress effect is strongly stress path dependent. As the sample is subjected to more cooling the stress state tends to approach an elasto-plastic formulation leading to a more soft response of the material. As a consequence the measured stress effect is lower than the estimated which was based on elastic state assumptions.