Effect of Methane Cracking on Carbon Isotope Reversal and the Production of Over-Mature Shale Gas

The geochemical statistics indicate that the wetness (C2~C5/C1~C5) of over-mature shale gas with carbon isotope reversal is less than 1.8%. The magnitude of carbon isotope reversal (δ13C1–δ13C2) increases with decreasing wetness within a wetness range of 0.9~1.8% and then decreases at wetness <0.9%. The experimental result demonstrates that CH4 polymerization proceeding to CH4 substantial cracking is an important factor involved in isotope reversal of over-mature shale gas. Moreover, δ13C1–δ13C2 decreases with an increase in experimental temperature prior to CH4 substantial cracking. The values of δ13C1 and δ13C2 tend to equalize during CH4 substantial cracking. The δ13C1–δ13C2 of mud gas investigated at different depths during shale gas drilling in the Sichuan Basin increases initially, then decreases with further increase in the depth, and finally tends to zero, with only a trace hydrocarbon gas being detectable. Thus, the approximately equal value between δ13C1 and δ13C2 for over-mature shale gas and very low wetness could potentially serve as useful criteria to screen CH4 substantial cracking. Two geochemical indices to indicate CH4 substantial cracking in a geological setting are proposed according to the variation production data with the geochemistry of over-mature shale gas in the Sichuan Basin, China

Geological features and formation of coal-formed tight sandstone gas pools in China: Cases from Upper Paleozoic gas pools, Ordos Basin and Xujiahe Formation gas pools, Sichuan Basin

The distribution of coal gas pools is controlled by many geological factors in China. The accumulation and pool-forming process of coal measures gas is studied from aspects of structure, source rock evolution, reservoir, pool-forming history, etc. The comparison results show that there are many similarities in geology between the Upper Paleozoic gas pools in Ordos Basin and the Upper Triassic Xujiahe Formation gas pools in Sichuan Basin, and the difference of the gas pools features in the two basins is caused by different structural evolutions and pool-forming processes. In Ordos Basin, water shoved by gas migrated from lower to higher positions in the formation process of the gas pools, and the abnormality of low gas reservoir pressure was caused by the water and gas reversal. In Sichuan Basin, structural traps controlled the gas pools distribution in Xujiahe Formation, lithologic gas pools was found locally, and the main factors for the abnormally high pressure are the undercompaction due to quick deposition, the hydrocarbon generation of source rocks and the structural compression during the Himalayan period. Key words: coal-formed gas, Ordos Basin, Sichuan Basin, Upper Paleozoic, Xujiahe Formation, pool-forming histor

Effect of Methane Cracking on Carbon Isotope Reversal and the Production of Over-Mature Shale Gas

The geochemical statistics indicate that the wetness (C2~C5/C1~C5) of over-mature shale gas with carbon isotope reversal is less than 1.8%. The magnitude of carbon isotope reversal (δ13C1–δ13C2) increases with decreasing wetness within a wetness range of 0.9~1.8% and then decreases at wetness 4 polymerization proceeding to CH4 substantial cracking is an important factor involved in isotope reversal of over-mature shale gas. Moreover, δ13C1–δ13C2 decreases with an increase in experimental temperature prior to CH4 substantial cracking. The values of δ13C1 and δ13C2 tend to equalize during CH4 substantial cracking. The δ13C1–δ13C2 of mud gas investigated at different depths during shale gas drilling in the Sichuan Basin increases initially, then decreases with further increase in the depth, and finally tends to zero, with only a trace hydrocarbon gas being detectable. Thus, the approximately equal value between δ13C1 and δ13C2 for over-mature shale gas and very low wetness could potentially serve as useful criteria to screen CH4 substantial cracking. Two geochemical indices to indicate CH4 substantial cracking in a geological setting are proposed according to the variation production data with the geochemistry of over-mature shale gas in the Sichuan Basin, China

The experimental study on H2S generation during thermal recovery process for heavy oil from the Eastern Venezuela Basin

Hydrogen sulfide (H2S) is toxic, corrosive and environmentally damaging. It is not only found in oil and gas development, but is also often found in heavy oil exploitation. In this study, three heavy oils were selected from the Orinoco Heavy Oil Belt in the southern part of the Eastern Venezuela Basin. Thermal cracking experiments in gold sealed tubes were then conducted using the heavy oils. The objective of the experiment is to unravel the H2S generation mechanism and utility in establishing a development program for heavy oil thermal recovery. The results of the oil isothermal cracking experiments show that the H2S yield increases with the increasing cracking temperature and holding time at 150 °C and 250 °C. Carbon dioxide (CO2) is the main component in gaseous products and its concentration is more than 80% in our experiments. The yields of CO2, H2S and total hydrocarbon gas present similar varying trend that increases with increasing isothermal time. The sulfur contents in group compositions of the original oil from the CJS-48 well and that of the residual oils with different cracking time at 250 °C were then measured. The analytical results show that most sulfur (>75%) exists in aromatics both in original oil and in the residual oils cracked at 250 °C, not to mention, no sulfur was measured in saturates. Although the decrease of sulfur in aromatics with the increased cracking time is low, it has great significance to the H2S generation during thermal recovery of heavy oil for more than 75% sulfur existed in aromatics. The decrease of sulfur content in resin and asphaltene of cracking residues with increased cracking time indicates that the sulfur existed in resin and asphaltene has some contribution to H2S generation during the thermal recovery process of heavy oil. Keywords: Venezuela, Heavy oil, Thermal recovery, H2S, Gold tube experiment

Evaluation of Recoverable Hydrocarbon Reserves and Area Selection Methods for In Situ Conversion of Shale

It is well known that the existing horizontal-well-drilling and hydraulic fracturing technology used to achieve large-scale, cost-effective production from immature to low–moderate-maturity continental shale in China, where the organic matter mainly exists in solid form, is fairly ineffective. To overcome the obstacles, in situ conversion technology seems feasible, while implementing it in the target layer along with estimating the amount of expected recoverable hydrocarbon in such shale formations seems difficult. This is because there are no guidelines for choosing the most appropriate method and selecting relevant key parameters for this purpose. Hence, based on thermal simulation experiments during the in situ conversion of crude oil from the Triassic Chang 73 Formation in the Ordos Basin and the Cretaceous Nenjiang Formation in the Songliao Basin, this deficiency in knowledge was addressed. First, relationships between the in situ-converted total organic carbon (TOC) content and the vitrinite reflectance (Ro) of the shales and between the residual oil volume and the hydrocarbon yield were established. Second, the yields of residual oil and in situ-converted hydrocarbon were measured, revealing their sensitivity to fluid pressure and crude oil density. In addition, a model was proposed to estimate the amount of in situ-converted hydrocarbon based on TOC, hydrocarbon generation potential, Ro, residual oil volume, fluid pressure, and crude oil density. Finally, a method was established to determine key parameters of the final hydrocarbon yield from immature to low–moderate-maturity organic material during in situ conversion in shales. Following the procedure outlined in this paper, the estimated recoverable in situ-converted oil in the shales of the Nenjiang Formation in the Songliao Basin was estimated to be approximately 292 × 108 tons, along with 18.5 × 1012 cubic meters of natural gas, in an area of approximately 8 × 104 square kilometers. Collectively, the method developed in this study is independent of the organic matter type and other geological and/or petrophysical properties of the formation and can be applied to other areas globally where there are no available in situ conversion thermal simulation experimental data