Callovian-Oxfordian sedimentary microfacies in the middle of Block B on the right bank of the Amu Darya Basin,Turkmenistan

The right bank of the Amu Darya Basin enjoys abundant natural gas resources,on which the Callovian-Oxfordian strata in the middle of Block B serve as the major horizons for natural gas production.However,the characteristics and distribution patterns of the sedimentary microfacies in these strata are yet to be further explored.Based on the analysis of data on drilling,logging,cores,and thin sections from 29 typical wells,as well as the regional sedimentary background,this study inferred that the middle of Block B evolved from the Callovian ramp platform into the Oxfordian rimmed platform.Moreover,this study determined that the inner-ramp intertidal-subtidal shallow-water subfacies mainly developed during the Callovian and transitioned into the shallow shelf subfacies during the Oxfordian.This study identified eight sedimentary microfacies,namely reef knoll,reef-shoal complex,bioclastic shoal,psammitic shoal,bioherm,lime mud mound,intershoal(intermound),and static-water mud.Based on research into the high-precision sequence-sedimentary microfacies framework,this study built a geological model for the development of sedimentary microfacies in the study area.According to this geological model,the sedimentary microfacies in the study area are characterized by vertical alternation of reef-shoal complex,bioclastic(psammitic)shoal,bioherm,and intershoal microfacies.Moreover,they show the development of reef knoll,reef-shoal complex,bioclastic(psammitic)shoal,and bioherm(or lime mud mound)laterally from west to east,with the physical properties of the reservoirs deteriorating from west to east accordingly.The microfacies of reef-shoal complex and the bioclastic(psammitic)shoal predominate in the study area,and their deposition and development are controlled by sequence boundaries and are also affected by paleo-landforms.The Oxfordian reef-shoal complexes were largely inherited from the Callovian uplifts and show lateral seaward progradation.

Carbonate reservoirs modified by magmatic intrusions in the Bachu area,Tarim Basin,NW China

Oil and gas exploration in carbonate rocks was extremely successful in recent years in the Ordovician in Tarim Basin.NW China.Here,we investigate the carbonate reservoirs in the Bachu area of the Tarim Basin through petrological and geochemical studies combined with oil and gas exploration data.Geochemical analysis included the major,trace,and rare earth elements;fluid inclusion thermometry;clay mineral characterization;and carbon and oxygen isotopes of the carbonate rocks.Homogenization temperatures of the fluid inclusions of Well He-3 in the Bachu area indicate three groups,60-80 ℃,90-130 ℃,and 140-170 ℃,and suggest that the carbonate rocks experienced modification due to heating events.The porosity in the reservoir is defined by fractures and secondary pores,and there is a notable increase in the porosity of the carbonate reservoirs in proximity to magmatic intrusion,particularly approximately 8-10 m from the intrusive rocks.The development of secondary pores was controlled by lithofacies and corrosion by various fluids.We identify supercritical fluids with high density（138.12-143.97 mg/cm3） in the Bachu area.The negative correlations of δ13C（-2.76‰ to-0.97‰） and δ18O（-7.91‰ to-5.07‰） suggest that the carbonate rocks in the study area were modified by high-salinity hydrothermal fluid.The formation of clay minerals,such as illite and montmorillonite,caused a decrease in porosity.Our study demonstrates the effect of magmatic intrusions in modifying the reservoir characteristics of carbonate rocks and has important implications for oil and gas exploration.

Reservoir characteristics and well-logging evaluation of the Lower Cambrian shales in southeast Chongqing, China

To accurately identify the reservoir characteristics and main controlling factors of the Cambrian Niutitang black shale in the southeast Chongqing,a series of systematic measurements were conducted on core samples from Well Yuke-1 and Well Youke-1.The measurements include clay mineral analysis,XRD analysis,petrophysical properties,specific surface area,pore diameter and TOC,as well as R_(o) and maceral compositions.The Niutitang shale reservoir contains detrital minerals and clay minerals averagely of 51.34%and 32.74%,respectively.The average effective porosity and permeability are 1.2%and 8.0×10^(-3)mD,respectively,typically of ultra-low porosity and permeability.Mesopores are dominant,accounting for approximately 73%of the total pore volume.The average BET specific surface area is 7.75m^(2)/g and the average pore diameter is 5.3nm.The average TOC is 2.29%and the average R_(o) is 3.12%,indicating that the organic matter is in over-maturity stage.Statistical analyses of the measurements show that the micropore volume is positively correlated with TOC but negatively correlated with the total content of clay minerals;the mesopore volume is positively correlated with TOC,the total content of clay minerals and the con­tent of carbonate minerals;the macropore volume is positively correlated with TOC and the con­tent of carbonate minerals,weakly positively correlated with the content of detrital minerals but negatively correlated with the total content of clay minerals.The porosity and TOC of the Niuti­tang shale are computed using the conventional well-logging method for the Yuke-1 and Youke-1 wells,and the porosities are quite consistent with the core analysis resultsr,but in the shallow res­ervoir that contains no oil and gas,the TOC exhibits no correlation with the core analysis results.

Origins and Differences in Condensate Gas Reservoirs between East and West of Tazhong Uplift in the Ordovician Tarim Basin, NW China

The Ordovician of the Tazhong area in the Tarim Basin has suffered multi-cyclic hydrocarbon charging, making Tazhong a typical condensate gas district. In this paper, production and test data were gathered and a detailed comparison was conducted on the geology and the fluid distribution and characteristics between the eastern and western Tazhong area. Eastern and western regions exhibit significant differences in tectonic structure, fluid distribution, and physical-chemical properties of oil and gas. Compared with the eastern region, the western part has a greater development of discordogenic gas associated with strike-slip faults which, combined with the Tazhong No. 1 fault zone, control the fluid distribution. The eastern region is mainly controlled by the Tazhong No. 1 fault zone. Fluid have markedly homogeneous properties in the east, but are heterogeneous in the west. The origins of oil and gas are different between the east and the west. In the east, hydrocarbons are mainly from Ordovician source rocks and natural gas is mostly derived from kerogen pyrolysis. In the west, the hydrocarbons mainly originated from Cambrian source rocks, and the gas was mostly generated by crude oil cracking. In sum, the east region is dominated by primary condensate gas reservoirs, and the western region is dominated by secondary condensate gas reservoirs. Because of the different geological settings and fluid physical properties, differences in the condensate gas reservoirs in the eastern and the western Tazhong area have been analyzed, and appropriate formation mechanisms for condensate gas origins are established.