Dang, Son (University of Oklahoma) | Gupta, Ishank (University of Oklahoma) | Chakravarty, Aditya (University of Oklahoma) | Bhoumick, Pritesh (University of Oklahoma) | Taneja, Shantanu (University of Oklahoma) | Sondergeld , Carl (University of Oklahoma) | Rai, Chandra (University of Oklahoma)
Mechanical characterization of an isotropic rock requires the measurements of at least two elastic constants. Dynamic constants are obtained using ultrasonic techniques and static constants are obtained from the stress-strain response of the rock; both techniques can be used at elevated pressures and temperatures. These methods typically involve the use of cylindrical plugs; however, the existence of natural fractures or fissility of shale formations precludes the extraction of cores. The challenge is to improve reservoir characterization by measuring elastic properties using irregular, but ubiquitous smaller rock samples. We propose measuring two elastic parameters, i.e., Young’s modulus and bulk modulus through nanoindentation and mercury injection capillary pressure (MICP) experiments, respectively. With these two constants and the assumption of isotropy, all other isotropic elastic constants can be derived. The idea is to infer Young’s modulus (Enano) using nanoindentation and estimate bulk modulus (KMICP) using MICP data; neither measurement requires core plugs and can be carried out on irregularly shaped rock fragments. We assume the fragments are representative of the formation of interest; confirmation comes from establishing statistics. We measured Woodford, Haynesville, Eagle Ford, Wolfcamp, Bakken, Utica and Green River shale core samples. These values are compared to values obtained in ultrasonic-pulse transmission experiments. Ultrasonic values of K measured at 5,000 psi confining pressure agree well with the values of KMICP at 5,000 psi. Similarly, Enano shows a 1:1 correlation with ultrasonically derived Young’s modulus at 5,000 psi confining pressure. At a confining pressure of 5,000 psi, the influence of cracks is reduced.
The ubiquitous use of hydraulic fracturing to stimulate unconventional reservoirs drives the need for improved methodologies to compute the mechanical properties of rock. Mineralogical variability (Rickman et al., 2008; 2009; Passey et al., 2010) in shale should be considered in the decision of the placement of laterals. Ductility is a function of mineralogy, TOC richness and in-situ stress profile. Within a stimulation zone, where principle stresses are minimally varied, mineralogical variability directly affects elastic properties (Al-Tahini et al., 2006), brittleness and ductility (Bai, 2016): High concentrations of clay make shale more ductile, while the predominance of quartz is associated with brittleness. Jarvie et al., (2007) related brittleness directly to mineralogy.
Besov, Alexander (University of Oklahoma) | Tinni , Ali (University of Oklahoma) | Sondergeld , Carl (University of Oklahoma) | Rai , Chandra (University of Oklahoma) | Paul , William (Encana Services Company Ltd.) | Ebnother , Danielle (Encana Services Company Ltd.) | Smagala, Thomas (Encana Services Company Ltd.)
Wells producing from the Tuscaloosa Marine Shale (TMS) have an initial production over 1,000 BOPD. Despite such significant hydrocarbon rates, the true potential and the factors controlling the production of hydrocarbon in the TMS remain elusive. Formation evaluation by logging and laboratory petrophysical measurements was performed to understand storage and production of hydrocarbons from this resource play.
A well was drilled, logged and cored through the Tuscaloosa Marine Shale formation. Field NMR and resistivity-based image logs were acquired. Laboratory NMR, mineralogy, total organic carbon (TOC), crushed rock porosity and SEM images were obtained on the core samples. The NMR measurements were conducted at the same echo spacing as the logging tool on “as-received” samples, after brine and dodecane imbibition, as well as on dodecane-saturated samples at 5,000 psi. T1-T2 maps were generated on the as-received and brine-imbibed samples.
The total clay content over the depth of investigation ranged from 25 to 81 wt%, averaging 63 ± 14 wt%. The dominant clays are illite and mixed-layer clays. Measured LECO™ TOC content is 1.6 ± 0.6 wt%. SEM images reveal that the organic matter is generally nonporous. Crushed helium porosity varies between 3.7 and 6.6%. The NMR porosity measurements show good agreement between the field and laboratory.
NMR results from imbibition and pressure saturation experiments reveal that the pore network is inaccessible to dodecane due to strong affinity for water and high capillary entry pressure. Vertical fractures are apparent in the image log in addition to microfractures observed in the SEM images. Based on the laboratory measurements, it appears that pores in the TMS cannot store hydrocarbons. Unlike other shale plays, hydrocarbons in TMS are likely stored and produced from microfractures, rather than from organic or inorganic porosity.