Application of Laboratory and Field NMR to Characterize the Tuscaloosa Marine Shale
- Alexander Besov (University of Oklahoma) | Ali Tinni (University of Oklahoma) | Carl Sondergeld (University of Oklahoma) | Chandra Rai (University of Oklahoma) | William Paul (Encana Services Company Ltd.) | Danielle Ebnother (Encana Services Company Ltd.) | Thomas Smagala (Encana Services Company Ltd.)
- Document ID
- Society of Petrophysicists and Well-Log Analysts
- Publication Date
- June 2017
- Document Type
- Journal Paper
- 221 - 231
- 2017. Society of Petrophysicists & Well Log Analysts
- 4 in the last 30 days
- 285 since 2007
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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.
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