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The top sandstone (S1) of the middle Triassic Karamay Formation (T2k) is one of the major pay zones in the Mahu field, Junggar Basin, northwestern China. Both spatial distribution and internal architecture of the reservoirs are important for resource evaluation and petroleum production in the field. Seismic sedimentology, an integrated study of seismic geomorphology and seismic lithology, was applied to well and three-dimensional (3-D) seismic data to analyze distribution of sedimentary facies and reservoirs. Lithologies in the study area consist of conglomerate, sandstone, and mudstone. Acoustic impedance (AI) of mudstone (6–9 × 106 kg/[s*m2]) is lower than the other two lithologies, which have similar AI values (9–14 × 106 kg/[s*m2]). Therefore, seismic amplitude can distinguish mudstone from conglomerate and sandstone, but fails to differentiate conglomerate from sandstone. Seismic geomorphology was employed to qualitatively predict distribution of sandstone and conglomerate respectively using frequency decomposition, seismic-attribute extraction, and red-green-blue (RGB) color-blending techniques. In the seismic lithologic study, principal component analysis (PCA) was utilized to transfer multiple seismic attributes into principal components. Selected principal components were then fit with cumulative reservoir thickness interpreted from porosity-log data, resulting in quantitative estimation of interwell thin (10 m or thinner) reservoir distribution. Meandering fluvial facies were recognized for the first time in the previously interpreted fan-delta facies zone. Meandering channels formed when the lake level rose in relatively humid climate during a time with few tectonic activities. The previously formed fan-delta was substituted by a later formed meandering channel, which flowed into the southwestern lake from the north. Sediment distribution was controlled by accumulation space or paleogeomorphology restored by cast method; sediment is thick in paleolow terrains and thin in paleohigh areas. Locality of reservoir rock is basically coincident with sandstone distribution. Thick reservoir rocks with high porosity (greater than 10%) are located mainly in areas with moderately thick sandstones formed in point-bar subfacies of fluvial systems and in lower-fan subfacies of the fan-delta system. Higher petroleum production in individual wells drilled in the fluvial system indicates superior physical properties there. As a result, locating point-bar subfacies is key to improving hydrocarbon exploration and development.

High-quality three-dimensional (3D) seismic data acquired in the central Sichuan Basin, southwestern China, offer an opportunity to map complex lithologies in a mixed siliciclastic–carbonate–evaporite system in the Lower Triassic Jialingjiang (T1j) Formation. The formation consists of siliciclastics, limestone, dolostone, anhydrite, and salt. The lithologies consist several source-reservoir-cap assemblages in the area. Lithologies in the T1j Formation change rapidly in the vertical direction, forming different interbed patterns in thin layers. In the mean time, the lateral extend of each lithology is complex. This vertical and lateral distribution makes it difficult to predict lithology by single seismic attribute. Therefore, principle component analysis (PCA) was applied to tens of seismic attributes to extract useful information. The first three components contain most (83.02–99.85%) of the lithology information preserved in seismic attributes, which were used to correlate with lithology content calculated by core-calibrated wireline logs. Correlation coefficients of the three seismic components with lithologies are significantly higher (0.37–0.79) than those of individual seismic attributes (near zero to 0.58). Different assemblies of end-member lithologies were selected from anhydrite, siliciclastics, tight dolostone, limestone, and salt to perform PCA in different sequences. Lithologic content distribution of individual end members was shown by color-blending method to map the lithology mixture. Sedimentary history in the T1j Formation was reconstructed based on lithology-mixture maps and regional geology background in the study area. Eight 4th-order sequences were interpreted in the T1j Formation. Only the second sequence was influenced by siliciclastic input, forming a complete mixed siliciclastic–carbonate–evaporite system. Open platform and/or restricted evaporative environment dominated the other seven sequences, forming a mixed carbonate–evaporite system.

This study is about factors controlling dolostone reservoir quality, and the material studied is cores, mainly from two wells, in deeply buried Early Cambrian Longwangmiao Formation in a recently discovered gas field in the Sichuan Basin. The vertical distribution of porosity in the formation was highly related to the presence of grainy lithofacies in manifold cycles and dissolution vugs, which in turn were controlled by multiple-order of sea-level fluctuations and paleotopography. The transgressive sections have very low porosity values, whereas the regressive sections demonstrate significantly better porosities. Pore networks are dominated by vugs, intercrystalline pores, and residual intergranular pores. The major diagenetic processes that affect reservoir quality include cementation, dissolution, dolomitization, and emplacement of bitumen. Primary intergranular pores were substantially decreased by marine and burial cementation. Early freshwater-related dissolution produced predominant vugs and locally enhanced intergranular pores, a key factor controlling the distribution of porosity. Intercrystalline pores are interpreted to be inherited from precursor rocks by rearrangement during dolomitization. Most pores were occluded partly, largely or completely by bitumen in the latest diagenetic stage, resulting substantial reduction in porosity. This work contributes to a better understanding of processes and controlling factors that have affected the Longwangmiao reservoir property, which may serve as an analog for many dolostone reservoirs worldwide, especially other Infra-Cambrian (Neoproterozoic–Early Cambrian) carbonate reservoirs.

Several giant biogenic gas fields (with proven gas reserves greater than 25 billion cubic meters) have been discovered in recent years in the Sanhu area of eastern Qaidam Basin. This area has an average surface altitude of around 2800 m, and forms the northern segment of the Qinghai-Tibet Plateau. The biogenic gas fields occur mostly within or adjacent to the depocenter of approximately 3400 m of Quaternary sediments. The gas reservoirs, with burial depth generally less than 1900 m, are unconsolidated sandstones with approximately 24–40% porosity, and are interbedded with mudstones containing on average 0.3% TOC. The occurrence of methanogens in the shallow Quaternary sediments appears to depend on both the sedimentary facies and burial depths, thus most of the biogenic gases in the Sanhu area appears to have derived from the source kitchens in the central sag above a biogenic gas floor at the depth around 1800 m. The key gas system elements for the formation of the giant biogenic gas accumulations include (1) secular low surface temperatures and lake water hypersalinity favor the preservation of suitable organic substrates for biogenic methane generation, (2) well-developed sand and mud interbeds, (3) sufficient cumulative thickness of water-saturated mudstones as caprocks, (4) presence of syndepositional anticlines of Pleistocene and later age, (5) a regional hydrogeological system favoring northeastward gas migration, and (6) ongoing dynamic gas migration and accumulation with abundant gas supply.

Since 1980s, oil and gas resource assessment in China has gone through five development stages. Resource assessment in different stages differs in data input, methodology and key parameters, resulting in significantly different conclusions on the oil and gas resource potential in China. The latest round oil and gas assessment in China was completed in 2005, with the following characteristics: (1) petroleum system analyses in superimposed sedimentary basins were conducted; (2) several methodologies were simultaneously used, including mass balance, geological analogy and statistical approach; (3) contrasting criteria areas were used to optimize the assessment parameters; and (4) not only resource in place but also recoverable resource were estimated for the assessment result. The assessment on 129 onshore and offshore basins indicates that the total aggregated mean conventional gas resource in China is 43.9 trillion cubic meters (tcm) or 1549 trillion cubic feet (tcf), including 26.9, 8.1 and 8.8 tcm in onshore, nearshore and southern South China Sea basins, respectively. The total recoverable conventional gas resource is around 27.5 tcm or 970 tcf, including 16.8, 5.3 and 5.4 tcm in onshore, nearshore and far offshore basins, respectively. Most of these resources are distributed in six areas, including the onshore Tarim, Ordos, Sichuan, Qidam and Songliao basins, and the offshore areas in the East China Sea and South China Sea.