The Gas Research Institute (GRI) conducted pioneering work on measuring shale petrophysical properties in the 1990s, however, despite growing interest in shales, there are still no set standards with respect to obtaining core petrophysical measurements due to the inherent complexity of shales. Core cleaning is one aspect of this problem.
The objective of this study is to shed some light on the shale core-cleaning conundrum. The study shows the cleaning impact of different solvents on samples from different maturity windows and having different in-situ fluids. It also compares the cleaning efficiency between plug and powdered samples. Different cleaning apparatus, such as the high-pressure extractor (HPE) and the Soxhlet extractor, are also compared.
Different measurements, such as source-rock analysis (S1 and S2 values); gas chromatography-mass spectrometry (GC-MS) extraction analysis; Brunauer-Emmett-Teller (BET) surface area and pore-size distribution help to understand the dynamics of core cleaning. This study was carried out on samples from the Wolfcamp and Eagle Ford formations.
Cleaning has a major impact on various petrophysical properties like porosity (increases up to 50%), S1 (decreases up to 90%) and surface area (increases by 450%). This study showed that cleaning time is a function of maturity and sample state. Samples in the oil-maturity window are much more difficult to clean compared to the samples in the gas-maturity window. Similarly, plug samples are more difficult to clean compared to the crushed samples. Our study shows that toluene, dichloromethane (DCM) and chloroform have similar cleaning efficiencies but n-heptane is less efficient.
Coring is an integral part of any exploration program. The planning for a coring program, coring fluids and corehandling procedures at the wellsite are all very important for preserving the core and getting accurate measurements in the laboratory.
The application of nuclear-magnetic-resonance (NMR) methods to evaluate the fluid content in hydrocarbon reservoirs requires the understanding of the NMR response of the fluids present in the rock. The presence of multiple fluids such as liquid, gaseous, or adsorbed phases in nanometer-sized pores (associated with various minerals and organic matter) adds another degree of complexity to the interpretation of NMR data in shales. We present a laboratory study on the NMR responses of brine, oil, and methane in shales at 2 MHz. NMR transverse relaxation time (T2) distributions were acquired on core plugs from the Haynesville, Barnett, and Woodford shale formations. The NMR T2 distributions were acquired after brine (2.5% potassium chloride) and oil (dodecane) imbibition and saturation. After brine imbibition, we observed an increase in porosity at T2 < 1 ms. However, after saturation at increasing pressures we observe a porosity increase at T2 = 6–20 ms. Dodecane imbibition and saturation induced a porosity increase at T2=10 ms. The measurements with methane were conducted on Haynesville core plugs at a methane pressure of 4,000 psi. The NMR T2 signal of methane in shales appears to be at approximately 10 ms. These results show that the NMR response of methane and oil is very similar in shales. Monitoring the saturation increase with NMR shows that brine can enter the entire pore spectrum, whereas oil and methane have access only to a fraction of the pore space.
The microstructure and mineralogy of any system define its chemical and physical properties. The heterogeneity of shale exists across multiple scales making accurate characterization difficult at any scale. In addition, heterogeneity has made linking variance in measured physical properties to the observed microstructural characteristics equally problematic. Because of the nano-scale components of shale, scanning electron microscopy (SEM) has proven invaluable as a tool for understanding microstructural and physical properties such as storage, storage partitioning between organic and inorganic phases, and fluid flow dynamics of shale. However, until recently, the restricted field of view of the SEM has limited its utility in yielding representative analysis of these complex rocks. The emergence of automated high-resolution imaging and stitching software permits bridging 7 orders of magnitude of scale using a single instrument. The collection of large images with nanometer-scale resolution is utilized to image and quantify microstructural characteristics from different shale plays. Image analysis on the stitched mosaic provides quantitative measurements of key microstructural elements. These features include, organic content, organic and inorganic porosity. In addition, mineralogy will be quantified using FTIR as well as an EDS-based approach for automated identification of the spatial mineralogy of each sample. The results of this detailed microstructural and mineralogical analysis are presented in the context of petrophysical measurements made on the same samples. Key petrophysical measurements include helium porosity, and NMR for porosity, TOC and pyrolysis for organic maturity as well as nano-indentation for defining mechanical properties of the samples.
Hydraulic fracturing is crucial to geothermal and hydrocarbon recovery. This process creates new fractures and reactivates existing natural fractures forming a highly conductive Stimulated Reservoir Volume (SRV) around the borehole. The fracturing process of anisotropic rocks such as shales is examined through this report. We divide the rock anisotropy into two groups: a) conventional and b) unconventional (shaly) anisotropy. As the first group, we study two extreme rock types: 1) Lyons sandstone, a brittle, low porosity and permeability, weakly anisotropic (11%) material and 2) pyrophyllite, a strongly anisotropic (19%) metamorphic rock similar chemically and mechanically to shale with extremely low porosity and permeability. As the second group, shale samples (18% anisotropy) from Wolfcamp formation are studied. The calcite filled veins are observed to be mostly subparallel to the fabric direction. Brazilian tests are carried out to observe the fracture initiation and propagation under tension. Strain gauges and Acoustic Emission (AE) sensors record the deformation leading to and during failure. SEM imaging and surface profilometry are employed to study the post-failure fracture system and failed surface topology. Fracture permeability is measured as a function of effective stress. The effect of anisotropy on fracturing is also investigated by rotating the fabric direction of the sample disks relative to the loading axis through increments of 15 degrees.
The rock microstructure, lamination, and brittleness control the activation of the layers. Lyons sandstone shows a wide brittle fracture with larger process zone with twice as much layer activation at lower stress levels. The fracturing process in shale is however a coupled function of rock fabric and calcite veins. The veins easily activate at 15 degrees orientation with respect to the loading axis at 30% of the original failure load. The resulting unpropped fracture has enhanced permeability by orders of magnitude. The findings of this research bring new insights toward an economic and efficient completion design. Fracking through a deviated well reduces the breakdown pressure significantly and activates a large number of veins with enhanced conductivity without the need for proppant injection.