Yan Song

The upper Paleozoic coalbed methane system in the Qinshui basin, China

The coalbed methane resource is very abundant in Qinshui basin (3.28 1012 m3; 114 tcf). The investigation on the upper Paleozoic coalbed methane system is a guide to the exploration and development of coalbed methane. The upper Paleozoic coalbed methane system in the Qinshui basin is sealed by a low-permeability roof and floor strata comprising mudstone, siltstone, and bauxite of the Carboniferous Benxi Formation and the Permian Shanxi and Xiashihezi formations. The overburden is the Lower Permian Xiashihezi Formation and the Upper Permian, Triassic, and Middle Jurassic clastic deposits. The source and reservoir rocks are the Carboniferous–Permian coal seams. The hydrocarbon generation of the source rocks reached its first peak in the Late Triassic. The highest maturity was about Ro = 1.2% under a normal paleogeothermal gradient (2–3C/100 m; 1.1–1.7F/100 ft). A tectonic thermal event during the Jurassic and Cretaceous Yanshanian orogeny enhanced the coal maturity and caused a second peak of hydrocarbon generation. Varying igneous intrusions caused the coal maturity to be higher in the southern, northern, and eastern parts of the Qinshui basin instead of the central and western parts. The highest maturity was greater than Ro = 4% in the Jincheng area. The migrated thermogenetic coalbed methane accumulated in the reservoirs in which abnormally high reservoir pressure exists locally under the hydrodynamic drive. Because of the different hydrodynamic background and sealing condition, the distribution of coalbed methane content is inhomogeneous. The reservoir is undersaturated with gas in most areas. Based on the coalbed methane system investigation, we assessed the coalbed methane producibility in different parts of the Qinshui basin, and the major producibility area is in the southern part of the basin.

The influence of tectonic evolution on the accumulation and enrichment of coalbed methane (CBM)

The current accumulation and enrichment of CBM reservoir is a result of the preservation and destruction of former CBM, after the superposing evolution of reversingand-uplifting and the subsequent evolution within the coalbearing basin. The critical moment of the CBM reservoir formation is the time when the burying depth of the overlying net thickness amounts to the least in geological history after the gas generation of coal beds. Except the coal-bearing basins of lower metamorphism, most basins suffered the evolution stage of reversion and uplift. The formation of the CBM reservoir is controlled by the beginning and lasting time, and the intensity of reversing and uplifting. The tectonic evolution after reversing and uplifting also affects the accumulation of CBM in coal-bearing basin. The CBM constantly dissipates in the area of chronically uplifting and denudating. The area developed overlying sedimentation is advantageous to the preservation of CBM, but also can lead to the reduction of CBM saturation.

Dominant factors of hydrocarbon distribution in the foreland basins, central and western China

Abstract Dominant factors controlling hydrocarbon distribution are analyzed from three aspects: the types, structural units and structural belts of the foreland basins of central and western China. There are four types of foreland basins recognized in China, superimposed, reformed, presenile, and newly-generated foreland basins. Hydrocarbon distribution is different in the four types of basins and is controlled by their respective hydrocarbon accumulation conditions, characteristics and patterns. Thrust belts, foredeeps, slope belts, uplift belts, and other structural units are developed in foreland basins. The different controls of these structural units on source rock development and evolution, trap type, hydrocarbon accumulation process, and preservation condition, cause different characteristics of hydrocarbon distribution in different structural belts. The main hydrocarbon enriched structural units are foreland thrust belts, in which the structural styles, tectonic evolution and the preservation of regional cap-rock are the critical factors for hydrocarbon accumulation. The configuration of faults and cap rocks in thrust belts determines the features and enrichment regularity of hydrocarbon and indicates hydrocarbon enriched locations and favorable exploration targets in various structural belts.

Genesis and distribution of natural gas in the foreland basins of China

Abstract This article discusses the geochemical characteristics of various types of natural gas and features of gas reservoirs in the foreland basins in China. We conclude that there are four types of natural gas in origin: coal-formed cracking gas, coal-formed thermal gas, oil-type thermal gas and mixed gas. Coal-formed gases are generated from three sets of coal measures: Permo-Carboniferous Formations in the Ordos Basin, Upper Triassic Formations in the Qaidam Basin, and Triassic Formations in northwest China. Source rocks for the oil-type gas include Permian Formations in the Junggar Basin, Triassic Formations in the Qaidam Basin, and lacustrine source rocks in basins along the Hexi Corridor. Abnormally high pressures commonly exist in the gas reservoirs in foreland basins where multiple sets of source–reservoir–seal combinations are present, and the major trap type is the anticlinal trap type and faults are the major hydrocarbon migration pathways.

Controlling factors for large gas field formation in thrust belt of Kuqa coal derived hydrocarbon foreland basin

Kuqa depression is a foreland basin developed with Mesozoic-Triassic-Jurassic coal-bearing formation. The research results of the coal-derived hydrocarbon foreland basins in Kuqa depression indicated that the coal-bearing formation can be the rich sources for generating gas because of their thickness and rich source rocks with gas-generating predominant kerogen. Although the foreland thrust belt mainly acting in compression is very complicated, integral large structural traps can be formed. Moreover, the thrust belt can act as the passage for communication with deep source rocks. The high quality gypsolish and gypseous mudstone cap rock developed in the upper formation is the key for the formation of the large gas field. The late formation of reservoirs in the large gas fields depended on the hydrocarbon-generating history controlled by the foreland basin and the developing process of foreland thrust belt.

Effects of early petroleum charge and overpressure on reservoir porosity preservation in the giant Kela-2 gas field, Kuqa depression, Tarim Basin, northwest China

Kela-2 is a giant gas field with a proven reserve of 597 tcf in the Kuqa depression, northern Tarim Basin. Widespread overpressures have been encountered in the Eocene and Cretaceous sandstone reservoirs of the field, with pressure coefficients up to 2.1 from drill-stem tests and well-log data analysis. Disequilibrium compaction associated with horizontal tectonic compression may be the dominant overpressure mechanism in the sandstone reservoirs, because the overpressured sandstone with a maximum burial depth over 6000 m (19,685 ft) displays anomalously high porosity and low density. The causes for sandstone reservoirs with anomalously high porosity in the Kela-2 gas field were studied based on an integrated investigation of sandstone reservoir characteristics, paleo oil–water contact, petroleum charge history, and overpressure evolution. Collective evidence indicates that early oil charge had retarded the porosity reduction of the reservoir sandstone and resulted in disequilibrium compaction from overburden rocks, and overpressure from disequilibrium compaction and horizontal tectonic compression at the beginning of the rapid subsidence and deposition in the Kela-2 gas field again contributed to the preservation of the reservoir porosity: (1) overpressured mudstones in the Kela-2 gas field are characteristic of normal compaction, and overpressure was generated by horizontal tectonic compression instead of disequilibrium compaction; (2) the reservoir sandstones with high porosity and permeability are associated with high paleo oil saturation, as indicated by quantitative grain fluorescence (QGF) responses and anomalous QGF on extract intensity; (3) sandstone units below the paleo oil–water contact have very low porosity and permeability; and (4) three episodes of oil and one episode of gas charge are identified in the sandstone reservoirs of the Kela-2 gas field, and the later two episodes of oil charge occurred circa 5.5–4.5 Ma, which corresponds to the beginning of the rapid tectonic subsidence and deposition in the Kuqa depression. The initially charged oil in the sandstone reservoirs was subsequently displaced by gas at circa 3–2 Ma through fault activation at the edge of the anticline trap. The overpressure evolution for the K1bs reservoir sandstone in the Kela-2 gas field indicates that the apparent overpressure development in the sandstone reservoir began at 5 Ma following the major oil charge and has been maintained to the present. Overpressure development from 5 Ma in the sandstone reservoirs of the Kela-2 gas field is believed to be the dominant cause of the porosity preservation.

The mechanism of the flowing ground water impacting on coalbed gas content

The hydrogeological condition affects the coalbed gas storage dramatically. In an area of stronger hydrodynamics, the coal has a lower gas content, while a higher gas content exists in an area of weaker hydrodynamics. Obviously, the flowing groundwater is harmful to coalbed gas preservation. But few researches focus on the mechanism of how the flowing water diminishes the coalbed gas content. Based on the phenomenon that the flowing groundwater not only makes coalbed gas content lower, but also fractionates the carbon isotope, this research puts forward an idea that it is the water solution that diminishes the coalbed gas content, rather than the water-driven action or the gas dissipation through cap rocks. Only water-soluble action can both fractionate the carbon isotope and lessen the coalbed gas content, and it is an efficient way to take gas away and affect the gas content.

Influence of overpressure on coalbed methane reservoir in south Qinshui basin

In theory, from the high temperature and pressure during the coal generating gas to the present low temperature and pressure of coalbed methane reservoir, the accumulation of coalbed methane was from oversaturated to undersaturated. The gas content of the coalbed methane reservoir in the south Qinshui basin was 12–35.7 m3/t. According to the isotherm and measured gas content of No. 3 coal, the adsorbed gas content in some wells was highly saturated and oversaturated, which was hard to theoretically understand. In addition, there were no thermogenic and biogenic gases at the late stage in the south Qinshui basin. This article proposed that the overpressure was the main reason for the present high saturation of the coalbed methane reservoir. In early Cretaceous, the coalbed methane reservoir was characterized by overpressure and high saturation caused by gas generation from coal measure source rocks. In late Cretaceous, the coalbed methane reservoir was rapidly uplifted, and with the temperature and pressure decreasing, the pressure condition of adsorbed gas changed from overpressure to normal-under pressure, which resulted in the high saturation and gas content in the present coalbed methane reservoir.

Hydrocarbon accumulation processes in the Dabei tight-gas reservoirs, Kuqa Subbasin, Tarim Basin, northwest China

The Dabei Gas Field is a recently discovered giant tight-gas field in the Kuqa Subbasin, western China. The reservoir porosity and permeability mainly range from 1% to 8% and from 0.01 to 1 md, respectively. The hydrocarbon (both gas and light oil) accumulation processes in the tight-sandstone reservoirs were studied based on detailed reservoir characterization, thermal maturity of both gas and light oil, hydrocarbon charge history, regional tectonic compression, and thrusting. Two episodes of oil and one episode of natural-gas charge were delineated in the tight-sandstone reservoir, as evidenced by (1) similar sources but different maturities for the gas and light oil, (2) the presence of abundant bitumen in the tight-sandstone reservoir, (3) the presence of both hydrocarbon gas inclusions and oil inclusions with two distinct fluorescence colors, and (4) the presence of two groups of aqueous inclusions (coeval with the petroleum inclusions) with contrasting homogenization temperatures and salinities. The oil inclusions with the blue-white fluorescence color were determined to have been trapped at 5–4 Ma, whereas the gas charge may have occurred at circa 3–2 Ma, corresponding to a salinity change recorded in the aqueous inclusions. The hydrocarbon accumulation processes appeared to be controlled by the tectonic compression of the South Tianshan Mountains. Intense tectonic compression caused thrust fault reactivation, which provided pathways for hydrocarbon migration. Overpressure evolution of the reservoir indicates that an intense tectonic compression began at circa 5 Ma, which caused thrust activation and concomitant oil charge into the relatively porous part of the reservoir. Subsequent tectonic compression caused uplift and erosion associated with thrusting at the end of the Kuqa Formation deposition (ca. 3 Ma), with thrust faults and fractures acting as major migration pathways for the gas accumulation in the already-tight sandstone reservoir resulting from both compaction and tectonic compression.

Study on process and model of CBM dissipating

Coal Bed Methane(CBM) occurs in coal seams in the states of adsorption gas, free gas and water-dissolved gas. Its dissipating starts with desorption, and then it dissipates outwards in the states of free gas and water-dissolved gas. The dissipating approach is classified to three patterns: Free gas in pores dissipates through the cover rocks; hydrocarbon molecules in the cap-rocks and reservoir diffuse because of concentration gradient; gas dissolving in water is directly taken away by water. According to the controlling factors of CBM conservation and considering the cover rocks, soleplate, hydrological region identification and dissipating theory, three geological models of CBM dissipating are built: closed system model, lateral hydrological closed model and open system model.