Accurate description of diagenetic controls on reservoir quality in “tight” sandstones can be difficult because of the inherent fine grain size and complex components of such oil reservoirs. In this study, petrological techniques and nuclear magnetic resonance (NMR) analysis were applied to fine-grained tight sandstones with varying grain sizes in order to reveal the diagenetic controls on reservoir quality. Results show that macropores in tight sandstones occur mainly as intergranular and dissolution pores, whereas micropores are distributed within ductile rock fragments, clay, and mica minerals, as well as occurring as dissolution micropores. Pore size distribution (PSD)/T₂ spectra display three distribution patterns: (i) a macropore-dominant bimodal distribution, (ii) a macropore–micropore bimodal distribution, and (iii) a micropore-dominant skewed distribution. A decrease in grain size correlates with weaker framework support of particles and thus more intensive mechanical compaction, resulting in the loss of both macroporosity and microporosity. Consequently, PSD change from macropore-dominant bimodal distributions to micropore-dominant skewed distributions as the pore type shifts from being dominated by macropores to intragranular micropores. In fine-grained sandstones, an increase in the abundance of ductile components corresponds to a loss of total porosity, related to the decrease in abundance of macropores, whereas the change in micropore abundance is negligible. This change is reflected in PSD by a shift from macropore-dominant bimodal distributions to macro–micropore bimodal distributions. The authigenic minerals in tight sandstone reservoirs occur mainly as late-stage carbonate minerals, and the precipitation of this carbonate cement preferentially occurs within macropores. When carbonate cement content is low, it has a limited influence on total porosity. However, it does significantly reduce the connectivity of the pore system, which is different from what might be expected in conventional sandstone reservoirs. Therefore, particle grain size, the abundance of ductile components, and late-stage cementation all contribute to the prediction of reservoir quality in oil-bearing tight sandstones.

中文翻译：

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细粒“致密”砂岩储层质量的成岩控制：基于NMR分析的案例研究

由于“致密”砂岩的固有细粒度和这类油藏的复杂成分，很难准确描述成岩作用对“致密”砂岩油藏质量的控制作用。在这项研究中，岩石技术和核磁共振（NMR）分析被应用于具有不同粒度的细粒致密砂岩，以揭示成岩作用对储层质量的控制。结果表明，致密砂岩中的大孔主要发生在粒间和溶蚀孔中，而微孔则分布在韧性岩石碎片，黏土和云母矿物中，并以溶蚀微孔存在。孔径分布（PSD）/ T ₂光谱显示三种分布模式：（i）大孔占主导的双峰分布，（ii）大孔占微孔的双峰分布，以及（iii）微孔占优势的偏斜分布。晶粒尺寸的减小与颗粒的较弱的骨架支撑有关，因此与更紧密的机械压实有关，从而导致大孔率和微孔率的损失。因此，随着孔隙类型从以大孔为主变为颗粒内微孔，PSD从大孔为主的双峰分布变为微孔为主的偏斜分布。在细粒砂岩中，韧性成分的丰度增加对应于总孔隙度的损失，这与大孔的丰度降低有关，而微孔丰度的变化可以忽略不计。通过从大孔占主导的双峰分布向大-微孔双峰分布的转变，这种变化反映在PSD中。致密砂岩油藏中的自生矿物主要是晚期碳酸盐矿物，而这种碳酸盐水泥的沉淀优先发生在大孔内。当碳酸盐水泥含量低时，它对总孔隙度的影响有限。但是，它的确会大大降低孔隙系统的连通性，这与常规砂岩储层中所期望的连通性不同。因此，颗粒大小，韧性成分的丰度和后期胶结作用都有助于预测含油致密砂岩的储层质量。致密砂岩油藏中的自生矿物主要是晚期碳酸盐矿物，而这种碳酸盐水泥的沉淀优先发生在大孔内。当碳酸盐水泥含量低时，它对总孔隙度的影响有限。但是，它的确会大大降低孔隙系统的连通性，这与常规砂岩储层中所期望的连通性不同。因此，颗粒大小，韧性成分的丰度和后期胶结作用都有助于预测含油致密砂岩的储层质量。致密砂岩油藏中的自生矿物主要是晚期碳酸盐矿物，而这种碳酸盐水泥的沉淀优先发生在大孔内。当碳酸盐水泥含量低时，它对总孔隙度的影响有限。但是，它的确会大大降低孔隙系统的连通性，这与常规砂岩储层中所期望的连通性不同。因此，颗粒大小，韧性成分的丰度和后期胶结作用都有助于预测含油致密砂岩的储层质量。但是，它的确会大大降低孔隙系统的连通性，这与常规砂岩储层中所期望的连通性不同。因此，颗粒大小，韧性成分的丰度和后期胶结作用都有助于预测含油致密砂岩的储层质量。但是，它的确会大大降低孔隙系统的连通性，这与常规砂岩储层中所期望的连通性不同。因此，颗粒大小，韧性成分的丰度和后期胶结作用都有助于预测含油致密砂岩的储层质量。