Pore Structure Of Tight Reservoirs Research Articles

Methodological Study on the Full-Range Pore Structure and Fractal Characteristics of the Tight Reservoirs

Scholars have used the method of splicing various experimental data to evaluate the full-range pore structure of tight reservoirs, but its applicability has not been discussed. When the fractal theory is used to characterize the heterogeneity of tight reservoirs, there is a lack of research on the controlling factors of segmented fractal pore size (the inflection points in the fractal curve) and the relationship between the fractal dimensions of different dimensions. In this paper, mercury intrusion porosimetry (MIP), N2 adsorption (N2-GA), and large-field splicing scanning electron microscopy (MAPs) were conducted to study the pore structure and full-range pore size distribution (PSD) of tight sandstone, and fractal theory was used to evaluate the heterogeneity of the reservoir. Combining the PSD of MIP and N2-GA, two parameters “cosine similarity” and “data similarity” were introduced to characterize the overlapping pore size range of the two experimental methods; then, the PSD of MAPs was used to verify the rationality of the data splicing. The results show that the characterization of the full-range pore structure should not only be based on simple data splicing but should focus on the data similarity of the overlapping pore size range. The study on the segmented fractal pore size of MIP shows that the segmented fractal pore size increases gradually with an increase in the main skeleton mineral content, the decrease in the clay mineral content, and the increase in the pore radius and porosity. For the same sample, the segmented fractal pore size is fixed and does not change with the calculation model of fractal dimension. Comparing the two-dimensional (2D) fractal dimension with the three-dimensional (3D) fractal dimension, calculating the 3D fractal dimension by +1 directly with the 2D fractal dimension is more applicable for the large pores, but it is not applicable for the small pores due to the influence of the extensive development of linear pores.

Qualitative and quantitative characterization of multiple factors that influence movable fluid saturation in lacustrine deep-water gravity-flow tight sandstones from the Yanchang Formation, southern Ordos Basin, China

Fluid mobility is one of the most important factors in evaluating the potential for recovering tight oil. However, quantitative effects of multiple factors that influence movable fluid saturation in different pore-throat combinations and their relationships with lithofacies in tight sandstones, especially for lacustrine deep-water gravity-flow deposits, remain controversial due to the strong heterogeneity and complex pore structure of tight reservoirs. Core samples obtained from the Upper Triassic Yanchang Formation in southern Ordos Basin were evaluated by using a variety of techniques, including nuclear magnetic resonance (NMR), scanning electron microscopy (SEM), X-ray diffraction (XRD), pressure-controlled porosimetry (PCP), rate-controlled porosimetry (RCP), impregnated thin sections, and helium porosity and nitrogen permeability measurements. Based on NMR T2 distributions under water-saturated and centrifugal conditions, four types of pore-throat combinations are identified by using the relaxation time thresholds Ts1 and Ts2 from NMR: large intergranular pore-dominated pore-throat combinations (LIP), small intergranular pore-dominated pore-throat combinations (SIP), intragranular pore-dominated pore-throat combinations (IAP), and micropore-dominated pore-throat combinations (MP). Among them, SIP is the dominant pore space favorable for fluid flow. Movable fluid saturation in SIP pore space varies among different lithofacies. The best fluid mobility commonly occurs in fine-grained, cross-bedded sandstones (Sc), whereas the worst fluid mobility usually appears in siltstones to very fine-grained sandstones (Ss). The quantitative effects of a total of 41 factors that influence movable fluid saturation of different pore-throat combinations were investigated through the analysis of the Pearson correlation matrix. The results demonstrate that porosity and permeability mainly affect the movable fluid saturation in the pore space of SIP and MP. In addition, maximum mercury intrusion saturation from PCP (Smax) and tortuosity (λ) are the critical pore structure parameters affecting the movable fluid saturation in the pore space of SIP and MP, whereas the average pore throat radius ratio (η) is the critical factor affecting the movable fluid saturation in LIP pore space. Overall, movable fluid saturation in different pore-throat combinations is characterized mainly by different microscopic pore structure parameters. A general pore network model for different lithofacies with different fluid mobility is established to facilitate assessment of the heterogeneity of tight sandstones and to further guide hydrocarbon exploration and development in similar lacustrine deep-water depositional settings.

A multiscale comprehensive study on pore structure of tight sandstone reservoir realized by nuclear magnetic resonance, high pressure mercury injection and constant-rate mercury injection penetration test

Abstract There is a large error in characterizing the pore structure of tight reservoirs in a single test. Based on this, the present study selected five samples of tight sandstone, and a multiscale comprehensive study was performed on the pore structure of tight sandstone reservoirs by scanning electron microscopy (SEM), casting thin sections (CTS), high-pressure mercury injection (HPMI), and constant-rate mercury injection (CMI) tests. The combined nuclear magnetic resonance (NMR) and HPMI test was performed to calculate the connectivity ratio of different samples, and evaluate the connectivity of tight sandstone reservoirs. Furthermore, the combined NMR and CMI test was performed to recalculate the pore throat radius of the sample, from quantitative characterization to qualitative analysis. This not only solves the shortcomings of the HPMI and NMR test, in which the throat could not be distinguished from the pore, but also solves the shortcomings of the CMI test, in which the pore radius calculated is larger than actual one and does not correspond to the CTS. On this basis, the lower limit of the movable fluid pore throat radius of tight sandstone reservoirs was investigated, and the results revealed that the lower limit of the movable fluid pore throat radius was not a constant value, in which the T 2 cutoff value corresponded to the pore throat radius, but a range that was determined through the saturation water curve and centrifugal curve. The upper and lower bounds of this range were r 1 and r 2 , respectively. According to r 1 and r 2 , the fluid state can be divided into three regions on the T 2 spectrum: irreducible region, transition region, and movable region. These results revealed that as the reservoir became tight, the r 1 and r 2 increased, and the proportion of irreducible fluid in the pores gradually increased.

Method on Pore Structure of Tight Reservoir

Method on Pore Structure of Tight Reservoir

A new method for grading and assessing the potential of tight sand gas resources: A case study of the Lower Jurassic Shuixigou Group in the Turpan-Hami Basin, NW China

Abstract A grading system from a pore structure perspective for assessing the quality of tight gas reservoirs in China is proposed based on an analysis of wettability, adsorption and pore throat size distribution and experiments including X-ray diffraction, contact angle measurement and static nitrogen adsorption, upon tight sand samples, from wells in Turpan-Hami Basin, western China. The hydrophilicity of tight sand has nothing to do with the overall clay content; instead, it is linked to the content of illite. Higher illite content means stronger hydrophilicity of the rocks. Indonesia's formula is proven to be more suitable for the interpretation of gas saturation measurement in tight reservoirs with higher content of illite. The microscopic pore structure of tight reservoir is clearly related to the porosity. The tight sandstone reservoir with low porosity is characterized by high proportion of small pores and high drainage pressure, while the tight sandstone reservoir with high porosity is characterized by high proportion of large pores, low drainage pressure and large average pore size. In view of endowment and flowing of tight sand gas, a new reservoir potential assessment parameter is established by porosity, permeability and gas saturation. The parameter relates to the porosity in a clear manner of trichotomy. Given the porosity of 6% and 4% as threshold, the tight sand gas can be divided into three types: I (Good), II (Potential) and III (Challenging). The trichotomy corresponds to a consistent porosity limit with the pore size change.