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SummaryTensile strength is a critical parameter for hydraulic fracturing, predicting fracture initiation and propagation in reservoirs, especially in shale reservoirs with complex natural fractures and fissures. The tensile strength of conventional rocks, such as sandstone and limestone, has been well-studied and -documented. There are many studies of the tensile strength of laminated shale, which focus on scale effects, loading direction, and temperature effects; however, the studies on effects of mineralogy and the water content on tensile strength of organic-rich shales are very limited.The objectives of this paper are to (1) critically review the key parameters that affect the tensile strength of shale and 2) experimentally examine the effects of water content, mineralogy, and lamination on tensile strength. To do so, a rigorous workflow is followed: 1) Each 1-in.-long shale sample is cut into two subsamples, A and B, of similar length; (2) X-ray computed-tomography (CT) scan is performed to diagnose pre-existing cracks and defects inside the core plugs; (3) nuclear magnetic resonance (NMR) is then used to measure the air dry samples’ water content; (4) Sample A is placed on a load frame to measure the tensile strength; (5) Sample B is vacuumed and then saturated; (6) NMR is used to measure the water content after saturation; (7) tensile strength of the saturated Sample B is measured; and (8) after the sample fails, the pieces are used for X-ray diffraction (XRD), scanning electron microscopy (SEM), and pyrolysis to estimate the mineralogy and total organic content (TOC).A total of 70 Mancos and 48 Eagle Ford shale samples have been tested. The experimental results show that (1) bedding plane/lamination has a significant effect on Eagle Ford tensile strength, but no pronounced impact is observed for the Mancos shale; (2) the imbibed water significantly reduces the tensile strength by 4.4 to 51.7% as water content increases from 4.45 to 11.7%; (3) pre-existing detectable microfractures can significantly reduce the tensile strength by up to 66%; (4) Eagle Ford exhibits typical brittle hard-rock failure configuration, with primary fractures and secondary fractures being observed, whereas for the Mancos shale, only primary fractures are observed; (5) acoustic velocity-test results confirm that Eagle Ford is mechanically transversely isotropic, and Mancos is likely mechanically isotropic.

Summary Acoustic-velocity measurements are an important nondestructive way to investigate dynamic rock-mechanical properties. Water content and bedding-plane-induced anisotropy are reported to significantly affect the acoustic velocities of siliciclastic sandstones and laminated carbonates. This relationship in organic-rich shales, however, is not well-understood and has yet to be investigated. The mechanical properties of organic-rich shales are affected by changes in water content, laminations, total organic content (TOC), and microstructures. In particular, kerogen density that accompanies changes in the composition of the TOC during maturity can significantly influence the acoustic responses within source rocks. To understand how these variables influence acoustic responses in organic shales, two sets of cores from the Eagle Ford shale were investigated: one set cut parallel to bedding and the other perpendicular to bedding. Textures of the samples from each set were characterized by use of computed-tomography (CT) scanning. Nuclear magnetic resonance (NMR) was used to measure the water content, and X-ray diffraction (XRD) to analyze the mineralogy. Scanning electron microscope (SEM) was also used to characterize the microstucture. Acoustic-velocity measurements were then made on each set at various confining pressures with the ultrasonic pulse-transmission technique. The results show that confining pressure, water content, and laminations have significant impact on both compressional-wave (P-wave) and shear-wave (S-wave) velocity. Both velocities increase as confining pressure increases. Velocities measured from cores cut parallel to bedding are, on average, 20% higher than those cut perpendicular to bedding. Increasing water content decreases both velocities. The impact of water content on shear velocity was found to be significant compared with the response with compressional velocity. As a result, the water content was found to lower both Young's modulus and shear modulus, which is opposite to the reported results in conventional reservoir lithology. In addition, both P- and S-wave velocities show a linear decrease as TOC increases, and they both decrease with increasing of clay content. The mechanisms that lead to water-content alteration of rock-mechanical properties might be a combined result of the clay/water interaction, the chemical reaction, and the capillary pressure changes.

Summary In a probe-type formation test, because of the geometry of the wellbore and the sealing effect of mudcake, the flow pattern is not perfectly spherical. To account for the deviation from spherical flow, several geometric correction factors were proposed for different analysis techniques (Steward and Wittmann 1979; Wilkinson and Hammond 1990; Dussan and Sharma 1992; Goode and Thambynayagam 1992; Proett and Chin 1996). A geometric factor is used in formation rate analysis (FRA) (Kasap et al. 1999), a technique used in analyzing a probe test to estimate formation pressure and permeability. Like other geometric correction factors, the geometric factor is a strong function of permeability anisotropy that is generally unknown before a test. When analyzing the test, we would logically assume an isotropic formation and use the corresponding isotropic geometric factor. Consequently, the FRA-estimated permeability does not represent the true spherical permeability. In contrast, the spherical permeability can be estimated from buildup analysis without prior knowledge of permeability anisotropy. Therefore, there is a discrepancy between the permeability estimates from the two analysis methods. In addition, if considered separately, neither FRA nor buildup analysis can decompose the estimated permeability into its horizontal and vertical components. This paper presents the derived numerical values of several geometric factors. Using these factors, we show that the discrepancy between the permeabilities estimated from FRA and from the conventional buildup analysis is attributable to the permeability-anisotropy effect. A correct geometric-factor value must be used to estimate permeability correctly. On the basis of the permeability-anisotropy effect, we present the procedures to estimate horizontal and vertical permeabilities by combining FRA permeability and buildup permeability or by history matching. These procedures are verified with a simulated probe test. Analysis of three actual tests is presented. Introduction A formation test is initiated when a probe from a formation tester is set and sealed against the formation. A measured volume of fluid is withdrawn from the formation through the probe. The test continues with a pressure buildup when fluid withdrawal is halted. Pressure in the tool is continuously monitored throughout the test. The flow pattern during the formation test using a probe is believed to be close to spherical flow. Because of the geometry of the wellbore and the sealing effect of mudcake, however, such spherical flow is imperfect. To account for deviations from spherical flow, several correction factors have been proposed. These correction factors include flow shape factor (Steward and Wittmann 1979; Wilkinson and Hammond 1990; Dussan and Sharma 1992; Goode and Thambynayagam 1992), geometric shape factor (Proett and Chin 1996), and geometric factor (Kasap et al. 1999). Although they have different forms or names, their physical meaning is the same. We use a general term, geometric factor, to represent these correction factors in this paper. The physical meaning of these factors is that because the actual relationship between pressure and flow rate in a probe-type test cannot be described by a spherical-flow equation, these factors are added in the spherical-flow equation to correct for the actual flow relationship. These correction factors are a function of permeability anisotropy, among other parameters. Similarly, the concept of geometric factor is applied to estimate permeability with mini-permeameters (Goggin et al. 1988; Georgi and Jones 1992; Jones 1994, 1997).

Summary Induced gamma ray spectroscopy (IGRS) logs from two cyclic-steam-stimulation observation wells in Cold Lake were analyzed to determine the vertical resolution and repeatability of data derived from gamma rays of inelastic and capture neutron reac tions. Time-series analysis, a technique that uses the Fourier representation of the log data, was used to quantify the vertical resolution and the signal/noise characteristics of various IGRS log curves and to compute the coherence vs. spatial frequency of data collected on multiple IGRS passes. The coherence function ranges from 1.0 for perfect repeatability to 0.0 for incoherent noise. Because no real variations in the measured data were expected for the 12- to 24-hour data-collection period, any deviation of the coherence function from 1.0 is attributed to incoherent noise. Generally, coherence is high at low frequencies (large vertical scales) and low at high fre quencies (small vertical scales). By noting the frequency at which the coherence level decreases to the expected value of random noise, we can quantify the vertical resolution of a log curve. Data analysis from these wells indicates that both the vertical resolution and repeatability of individual capture and inelastic curves differ. We found that the H-yield and capture curves have the highest vertical resolution (≈0.3 m) and the best signal/noise ratios (FSN≈30:1). In contrast, the capture Ca and Si yields are of significantly lower quality (FSN≈2:1). Only a small difference exists between the vertical resolution of the inelastic C (1.0 m) and O (1.3 m) yields, but the FSN the O yield is only one-half that of the C yield. Fortunately, the vertical resolution and the repeatability of the C/O ratio, FCO, are determined primarily by the quality of the inelastic C data. Specific to our application of monitoring heavy-oil saturations during cyclic-steam stimulation in a relatively uniform, high-porosity unconsolidated sand, we developed a simplified FCO interpretation that does not rely on the elemental yields from capture data. This linear model permits us to assess the uncertainties in computed saturations from the statistical noise in the inelastic FCO data.