A new method for measuring shale porosity with low-field nuclear magnetic resonance considering non-fluid signals. (April 2019)

• Record Type: Journal Article
• Authors: Li, Jinbu; Lu, Shuangfang; Chen, Guohui; Wang, Min; Tian, Shansi; Guo, Zhiqiang
• Is Part Of: Marine and petroleum geology. Volume 102(2019)
• Page Start: 535
• Page End: 543
• Publication Date: 2019-04
• Subjects: NMR -- Shale -- Porosity -- T2 distribution -- Organic matter; Submarine geology -- Periodicals; Petroleum -- Geology -- Periodicals; Géologie sous-marine -- Périodiques; Pétrole -- Géologie -- Périodiques; Petroleum -- Geology; Submarine geology; Periodicals; Electronic journals; 551.468
• DOI: 10.1016/j.marpetgeo.2019.01.013
• Languages: English
• ISSNs: 0264-8172

Abstract

Abstract: Porosity is a key parameter for the evaluation of potential shale oil and gas resources. Low-field nuclear magnetic resonance (NMR) is a rapid technique for measuring shale porosity without causing damage to the testing samples. Previous NMR methods for porosity characterization are mainly based on the NMR T2 distribution of saturated oil shale, but for shales with high total organic carbon (TOC) and clay mineral contents, not all signals of NMR detection originate from the pore fluid. Nine continental shales in Damintun Sag were selected and subjected to pyrolysis, X-ray diffraction (XRD), mercury injection capillary pressure (MICP), weighing before and after fluid saturation, and NMR tests to improve the accuracy of NMR porosity measurements. According to the NMR T2 distribution and T1 –T2 map of shale with different oil contents (original, extracted, and saturated oil states), we revealed that the non-fluid signals (kerogen and structural water) accounted for 15.77%–43.10% (with a mean of 28.87%) of saturated oil shale. A stronger NMR signal intensity was observed for the extracted shale with higher TOC and clay mineral contents. A ΔT2 distribution of oil present in the pores of oil-saturated shale was constructed based on the difference between the oil-saturated shale and extracted shale and was combined with the calibration equation of oil (the relationship between oil volume and its NMR signal intensity) to directly evaluate the porosity. The porosity that was calculated based on the ΔT2 distribution versus the weighing method had an absolute error of ≤0.7%, and the relative error was <10%. Compared with the previous NMR method, the new method does not require optimization of the NMR parameters and considers the contribution of organic matter and clay minerals to NMR signals, which is more suitable for the porosity evaluation of shales with high TOC and clay mineral contents. The results of this study are helpful for NMR characterization of the porosity in shales. Highlights: The NMR T2, T1 –T2 characteristics of organic-rich continental shale with different oil contents were discussed. Non-fluid components (kerogen and structural water) have high NMR signals in the saturated oil shales was revealed. A new NMR method for measuring the porosity of organic-rich shale was established.