Search

Micro-nano scale pores can accurately and fastly be measured by the nuclear magnetic resonance (NMR) technique, which provides a new method to quantitatively characterize pore structures in tight sandstone. Based on the method of calibration of mercury pressure data for NMR T2 spectrum, for the measurement inaccuracy due to the mercury saturation less than 100% in tight sandstone, the mercury pressure curve and T2 spectrum is used to cumulate from the maximum pore on the right boundary to the small pores in the left, the range of pore-throat radius measured by the mercury injection in the leftward cumulative curve is selected as a comparable interval of NMR pore-throat radius, and the longitudinal interpolation method and the least square method are utilized to construct the distribution curve of pore-throat radius transformed by T2 spectrum. The modified method is used to obtain NMR T2 spectrum, conversion coefficient of pore-throat radius and pore-throat radius distribution of the Carboniferous-Permian tight sandstone gas reservoirs in the eastern Linqing depression, and characteristics of reservoir pore structures are quantitatively investigated; in addition, in combination with analysis of thin section and scanning electron microscopy, the reservoir effectiveness and cause of the pore structure variability in the tight sandstone are also well studied. The results show that the NMR pore-throat radius curve obtained by the modified method has a high consistency with the mercury injection curve, and the NMR test accuracy of tight sandstone is significantly improved. In the study area, the pore-throat radius of the Carboniferous-Permian tight sandstone mainly ranges from 0.002 to 2 μm, the pore is generally submicro-nano scale, but the pore-throat radius distribution of different types of sandstone varies significantly. The lithic quartz sandstone is rich in siliceous matter and poor in plastic detritus and matrix, generally dominated by submicro-scale pore-throats including micro-scale pore-throats; lithic feldspar sandstone and quartz-rich feldspar lithic sandstone are rich in quartz and poor in plastic detritus and matrix, dominated by submicro-nano scale pore-throats (nano-scale pore-throats predominantly); the lithic fragment-rich feldspar lithic sandstone and lithic sandstone are poor in quartz and rich in plastic detritus and matrix, mainly dominated by nano-scale pore-throats smaller than 0.05 μm. Micropetrographic components are key factors to control pore structure difference and reservoir effectiveness, and the reservoir quality may be macroscopically controlled by sedimentary microfacies; the lithic quartz sandstones of coarse- and fine-grained point bar/riverbed microfacies are the most favorable reservoirs; the lithic feldspar sandstone of fine-grained point bar microfacies, the quartz-rich feldspar lithic sandstone of fine-grained distributary channel and barrier bar microfacies are relatively favorable reservoirs, while both lithic fragment-rich feldspar lithic sandstone and lithic sandstone of tidal-flat facies are ineffective reservoirs with very poor porosity and permeability. Keywords: NMR T2 spectrum, Mercury injection, Conversion coefficient, Pore-throat, Rock fabric, Microfacies, Tight sandstone, Linqing depression

Thick tight Ordovician carbonate rocks are present at depths exceeding 5300 m in the Tahe oilfield and their matrix is considered to contain no storage space. An integrated petrographical and petrophysical study was conducted on a set of 25 tight carbonate core samples from Ordovician strata, covering a wide range of lithologies and textures. Six carbonate rock types were characterized by integrating both petrographical and petrophysical data, including thin-section observations and porosity, permeability, mercury injection capillary pressure and nuclear magnetic resonance (NMR) measurements. We found that thick grainstone and limestone with half-filled fractures exhibited good reservoir properties. NMR testing is an invaluable tool for characterizing pore structures in tight carbonate rocks. For example, six rock types can be identified from the NMR T2 distributions and the changes in pore volume under different pressures (up to 20 MPa) can be calculated. NMR technology can be used to perform rapid and accurate rock-type identification and pore network evaluation in tight carbonate rocks. The results provide an experimental foundation for NMR logging interpretations and advance the understanding of geological and geophysical characteristics of ultra-deep carbonate reservoirs.

Tight oil as a significant part of unconventional resources is now considered as one of most important alternative resources. Oil accumulation mechanism is still a research focus for the tight oil. Therefore, it is important to study the effectiveness of micro-nano pore system to oil charging and accumulation. Taking the Chang 7 tight sandstone reservoir of the Ordos Basin as an example, the physical simulation experiment of oil charging is applied to study the pore throat threshold of tight sandstone reservoir under the different charging force using the nuclear magnetic resonance (NMR) combined with displacement techniques. The relationship between charging force and pore throat radius threshold (Rth) can be established when combined with the pore throat distribution derived from MICP. In addition, the effectiveness of oil accumulation for the different type tight sandstone reservoir is also discussed. The result shows that the Chang 7 tight sandstone reservoir is divided into four groups based on pore structure and petrophysical property (porosity and permeability). In the physical simulation experiment, the oil saturation growth trend can be roughly divided into three groups: uniform growth model, slow growth-stable model, fast-slow growth model. This result indirectly reflects the heterogeneity of pore structure. There is a power function relationship between the charging force and Rth of oil charging, which can be used to calculate the effective accumulation space and further determine the accumulation effectiveness. The effectiveness of oil accumulation changes with the increase of the charging force: the effective accumulation space increases with the charging force, which causes that the reservoir (usually not including type III) gradually transits from ineffective accumulation to effective accumulation. That is, the charging force coupled with pore throat radius controls oil charging and accumulation. For the Chang 7 tight oil accumulation, the effective pore throat radius threshold of oil charging is about 0.1 μm and thus only the type I and II1 reservoirs can become the effective tight oil reservoirs, which is the main target of tight oil exploration. This result not only puts insight into the tight oil accumulation mechanism but also plays an important role in the tight oil exploration of Yanchang Formation in the Ordos Basin.

Paleokarst systems are major carbonate reservoirs that can form significant and very large oilfields. The Ordovician carbonate reservoirs of the Tahe Oilfield represent a special type of hydrocarbon reservoir consisting primarily of paleokarst caves and fractures. Detailed characterization of paleokarst reservoirs in the Tahe area is challenging because of their heterogeneous distribution and, in particular, because these reservoirs are at depths exceeding 5500 m. This paper describes a detailed approach for integrating data from cores, imaging and conventional well logs, and high-quality seismic datasets to delineate the complex paleokarst systems in the Tahe Oilfield, particularly the paleocaves in the run-off zone. Based on the hydrologic genetic relationships between the karst and paleocaves observed in outcrops, we divided the paleocaves in the run-off zone into chambers, main channels, and branch channels. The chambers, which are generally taller than 15 m, are generally collapsed. The main channels, mostly 5–15 m tall, were the main passages for underground water flow and display good connectivity. The branch channels, typically less than 5 m tall, are relatively dispersed and still have a considerable volume. This method was applied to the area around Well T615, and two layers of paleocaves in the run-off zone were interpreted. Seismic mapping and three-dimensional modeling of the paleocaves were performed, and the lengths, widths, areas and volumes of these three types of paleocaves were statistically analyzed. Although most of the chambers have been penetrated by existing wells, the areas where the main channels and a dense network of branch channels developed are favorable targets for future drilling in the Tahe Oilfield. Our method of detecting and analyzing the paleokarst reservoir structure is applicable to similar paleokarst reservoirs.

By supplementing standard relaxation time measurements with diffusion information, nuclear magnetic resonance (NMR) D–T 2 mapping provides a powerful tool for characterizing fluids in a core. In this study, a D–T 2 mapping technique was designed and applied to investigate waterflooding behavior and pore-level residual oil distributions. NMR measurements were conducted at different stages of the waterflooding process, and corresponding D–T 2 maps were acquired. The oil and water signals were easily separated using a diffusion coefficient cut-off of 3 × 10−6 cm2/s. The oil saturation values measured via the NMR method were highly consistent with the volumetric method results. The pore-level residual oil distributions could be calculated by analyzing the oil T 2 spectra during waterflooding. The injected water was found to preferentially displace oil in large and medium-sized pores having relatively low capillary pressures. The final residual oil saturation measured via the NMR method was 18.9 %, with 15.7 % occurring in medium-sized pores (10 ms