Seismic sedimentologic study of facies and reservoir in middle Triassic Karamay Formation of the Mahu Sag, Junggar Basin, China. (September 2019)

• Record Type: Journal Article
• Authors: Xu, Zhaohui; Hu, Suyun; Wang, Lu; Zhao, Wenzhi; Cao, Zhenglin; Wang, Ruiju; Shi, Shuyuan; Jiang, Lei
• Is Part Of: Marine and petroleum geology. Volume 107(2019)
• Page Start: 222
• Page End: 236
• Publication Date: 2019-09
• Subjects: Seismic sedimentology -- Faces -- Reservoir -- Middle Triassic -- Karamay Formation -- Mahu Sag -- Junggar Basin; 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.2019.05.012
• Languages: English
• ISSNs: 0264-8172

Abstract

Abstract: The top sandstone (S1 ) of the middle Triassic Karamay Formation (T2 k) 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 × 10 6 kg/[s*m 2 ]) is lower than the other two lithologies, which have similar AI values (9–14 × 10 6 kg/[s*m 2 ]). 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. Highlights: A seismic sedimentologic workflow, combining phase rotation, frequency decomposition, RGB color blending, seismic-attribute generation, and PCA, was established and proven to be effective in studying sedimentary facies and reservoir distribution in a fan-delta dominated environment in Mahu Sag Junggar Basin. In an environment with mixed lithologies of conglomerate, sandstone, and mudstone: seismic amplitude can distinguish mudstone from sandstone/conglomerate based on the lower AI of mudstone; seismic geomorphology is useful in differentiating sandstone from conglomerate. Paleogeomorphology and accommodation space regulates distribution of conglomerate, sandstone, and mudstone. High-porosity (over 10%) reservoirs exist in sandstone with moderate thickness formed in lower-fan subfacies of the fan-delta system and point-bar subfacies of the fluvial systems. Daily oil production of wells drilled in the fluvial system is much higher than that of wells drilled in the fan-delta system, which indicates superior reservoir properties in the fluvial facies. Physical data from key wells prove this conclusion. Within one point bar, the higher daily production of well located in the upstream direction than well located in the downstream direction evidences higher permeability in the upstream location.