Hydrocarbon Generation Capacity Research Articles

Resource Potential Classification Evaluation of E<sub>2</sub>S<sub>4</sub><sup>2</sup> Shale Oil in Damintun Depression

Shale oil resource potential classification evaluation is needed to precisely calculate the resource potential and prepare for the prediction of shale oil sweet spots. Geochemical analysis results shows that the E2S42 shale in Damintun Depression has strong hydrocarbon generation capacity. The classification evaluation criteria of E2S42 Shale oil in Damintun Depression was established according to the triple-division characteristic of measured TOC vs. S1. The shale oil oiliness parameter S1 was obtained by using improved logR method. The loss of hydrocarbon was recovered by chemical kinetics method. Volumetric method was used to calculate different grades of E2S42 shale oil in Damintun Depression. Grade I resource is 334 million tons. Grade II resource is 33 million tons. Grade III resource is 15 million tons. Grade I resource accounts for over 90% of the total resource content. High value area mainly concentrated near Well Shen223 and Well Shen224. Results shows that the E2S42 shale in Damintun Depression has good resource potential.

UPPER TRIASSIC POTENTIAL SOURCE ROCKS IN THE QIANGTANG BASIN, TIBET: ORGANIC GEOCHEMICAL CHARACTERISTICS

Upper Triassic coal‐bearing strata in the Qiangtang Basin (Tibet) are known to have source rock potential. For this study, the organic geochemical characteristics of mudstones and calcareous shales in the Upper Triassic Tumengela and Zangxiahe Formations were investigated to reconstruct depositional settings and to assess hydrocarbon potential. Outcrop samples of the Tumengela and Zangxiahe Formations from four locations in the Qiangtang Basin were analysed. The locations were Xiaochaka in the southern Qiangtang depression, and Woruo Mountain, Quemo Co and Zangxiahe in the northern Qiangtang depression.At Quemo Co in the NE of the basin, calcareous shale samples from the Tumengela Formation have total organic carbon (TOC) contents of up to 1.66 wt.%, chloroform bitumen A contents of up to 734 ppm, and a hydrocarbon generation capacity (Rock‐Eval S1+ S2) of up to 1.94 mg/g. The shales have moderate to good source rock potential. Vitrinite reflectance (Rr) values of 1.30% to 1.46%, and Rock‐Eval Tmax values of 464 to 475 °C indicate that the organic matter is at a highly mature stage corresponding to condensate / wet gas generation. The shales contain Type II kerogen, and have low carbon number molecular compositions with relatively high C21−/C21+ (2.15–2.93), Pr/Ph ratios of 1.40–1.72, high S/C ratios (>0.04) in some samples, abundant gammacerane (GI of 0.50–2.04) and a predominance of C27 steranes, indicating shallow‐marine sub‐anoxic and hypersaline depositional conditions with some input of terrestrial organic matter.Tumengela and Zangxiahe Formation mudstone samples from Xiaochaka in the southern Qiangtang depression, and from Woruo Mountain and Zangxiahe in the northern depression, have low contents of marine organic matter (Type II kerogen), indicating relatively poor hydrocarbon generation potential. Rr values and Tmax data indicate that the organic matter is overmature corresponding to dry gas generation.

The Volumetric Calculation of Hydrocarbons Generation of Source Rocks in the Gulf of Suez, Egypt

Regression lines obtained from TOC versus S 2 graphs of organic rich samples were collected from Rahmi, West Bakr, Ras Gharib, and Esh El Melleha wells in the Gulf of Suez. By applying the hydrogen index values obtained from S 2 versus TOC graph and mass balance calculations obtained from the results of Rock-Eval pyrolysis, the original hydrocarbon generative capacity and the amounts of the hydrocarbons generated are estimated. Calculation results indicate that the amounts of original hydrocarbons and the hydrocarbon generative capacities of the two methods are similar and correlated with the results of the Rock-Eval pyrolysis. This indicates that such calculations can be applied in the hydrocarbons evaluation of source rocks.

Formation overpressure and shale oil enrichment in the shale system of Lucaogou Formation, Malang Sag, Santanghu Basin, NW China

Abstract According to observation of cores and thin sections, as well as analyses of fluid pressure features and geochemical indexes, the cause of fluid overpressure and the mechanism of shale oil enrichment in the Lucaogou Formation, Malang Sag, Santanghu Basin, were discussed. The results show that the shale oil of the Lucaogou Formation is generated in the low mature–premature stage of the source rocks and has the features of high density and high viscosity. The low-permeability and thick source rocks lead to high start-up resistance of fluid, which made it difficult for oil and gas to expel, so the retainment of oil and gas in source rocks is the major cause of formation overpressure. Excellent generation potential and well developed reservoir space are the basis for the oil retention; the pressure produced by hydrocarbon generation is not high enough to overcome the resistance of oil migration, which leads to the enrichment of shale oil. The enrichment degree of shale oil is controlled by hydrocarbon generation and storage capacity of lithofacies at various evolution stages.

Sedimentary association of alternated mudstones and tight sandstones in China’s oil and gas bearing basins and its natural gas accumulation

Oil and gas resources are abundant in China’s continental sedimentary basins, where the main task of exploration has been finding oil for many years. In recent years, however, new discoveries of large-scale natural gas have been successively obtained. The natural gas mainly exists in the sedimentary association of alternated mudstones and tight sandstones and is dominantly low-permeability tight sand gas. Through the in-depth study on gas reservoir analysis, diagenetic evolution, source rock distribution and hydrocarbon-generating behavior, natural gas generation and accumulation, it is concluded that, during the major subsiding stage of large scale lake basins, the multicyclic subsiding process of the lake surface controls the development of high quality source rocks, the wide distribution of sands, and the superimposition of the two types of rocks in the vertical direction. The lacustrine muddy source rocks are developed, including mud shale, carbonaceous mudstone and coal bed which are in the medium–high evolution stage and produce mainly gas and the gas generation intensity is high. Through the analysis of the subsidence evolution processes of the Carboniferous–Permian Systems (transitional marine–continental facies) in the Ordos Basin and the Triassic Xujiahe Formation (continental facies) in the Sichuan Basin, it is concluded that the widely distributed sandbodies of delta facies, although with tight properties, are interbedded with source rocks and easy to accumulate natural gases. The natural gas is migrated and accumulated within small distance, and is characterized by large-area accumulation. Because of the strong hydrocarbon generation capacity, big thickness and stable distribution of the underlying mud shale, the potential of gas resources should not be underestimated. The geocyclicity of China’s continental sedimentary basins controls the sedimentary association of alternated mudstones and tight sandstones, resulting in superimposed accumulations of shale gas and tight sand gas.

SOURCE ROCK THERMAL AND MATURITY HISTORY MODELING IN C SAG OF THE WEIXINAN DEPRESSION, BEIBUWAN BASIN

It is significant to study the source rock maturity history in the C sag of the Weixinan depression for the deep water exploration in this area of Beibuwan basin.Based on geohistory and thermal history of the C sag,the source rock maturity history of the sag is reconstructed with the usage of Easy%Ro model.The studies indicate:(1)In the early rifting stage,the heat flow in the C sag of the Weixinan depression reached the maximum(77 mW/m2),then decreased gradually and is about 54 mW/m2 at present.(2)The Liushagang Formation source rock in the C sag began to generate hydrocarbon(Ro=0.5%)at about 51 Ma,reached the hydrocarbon generation peak(Ro=1%)at about 42 Ma,and the high maturity(Ro=1.3%)at about 17 Ma.(3)Comparatively,maturity of the Liushagang Formation source rock of Well Wei1,in the deep water exploration area is higher and the hydrocarbon generation capacity is stronger,so the deep water exploration area has more cheerful prospect.

SOURCE ROCK THERMAL AND MATURITY HISTORY MODELING IN C SAG OF THE WEIXINAN DEPRESSION, BEIBUWAN BASIN

It is significant to study the source rock maturity history in the C sag of the Weixinan depression for the deep water exploration in this area of Beibuwan basin.Based on geohistory and thermal history of the C sag,the source rock maturity history of the sag is reconstructed with the usage of Easy%Ro model.The studies indicate:(1)In the early rifting stage,the heat flow in the C sag of the Weixinan depression reached the maximum(77 mW/m2),then decreased gradually and is about 54 mW/m2 at present.(2)The Liushagang Formation source rock in the C sag began to generate hydrocarbon(Ro=0.5%)at about 51 Ma,reached the hydrocarbon generation peak(Ro=1%)at about 42 Ma,and the high maturity(Ro=1.3%)at about 17 Ma.(3)Comparatively,maturity of the Liushagang Formation source rock of Well Wei1,in the deep water exploration area is higher and the hydrocarbon generation capacity is stronger,so the deep water exploration area has more cheerful prospect.

Calculation of the Amounts of Hydrocarbons Generated from the Lower Antalya Nappes, Western Taurus Region: The Importance of the Fractional Conversion (f) Value

Applying the corrected Hydrogen Index values obtained from S 2 vs. TOC graph in conjuction with the results of Rock-Eval pyrolysis and mass balance calculations provide estimations of the original hydrocarbon generative capacity and the amounts of hydrocarbons generated. For calculations and a comparison between three different approaches were applied to 27 organic-rich samples collected from the Dereköy Formation shales which are mainly characterized by oil-prone Type-II kerogen that is in different thermal maturity levels. Such calculations indicate that (1) the results of the calculated amounts of original hydrocarbons are mostly over 100,000 ppm, (2) the results of the hydrocarbon generative capacities from two methods which include fractional conversion value are in accordance, and, are over 5000 ppm, and (3) when the fractional conversion values are low (ranging from essentially zero to 0.5%), indicating thermally immature stage, the calculation results of three methods are almost similar.

97/04500 Hydrocarbon generation capacity of small molecules in coal: Pan, L. et al. Chongehun Dizhi Xueyuan Xuebao, 1996, 26, (3), 356–359. (In Chinese)

97/04500 Hydrocarbon generation capacity of small molecules in coal: Pan, L. et al. Chongehun Dizhi Xueyuan Xuebao, 1996, 26, (3), 356–359. (In Chinese)

BASIN RICHNESS AND SOURCE ROCK DISRUPTION — A FUNDAMENTAL RELATIONSHIP?

Primary petroleum migration (expulsion from source rocks) remains the least understood parameter controlling the genesis of oil deposits. In spite of this lack of understanding, many petroleum geochemists (including this Author) have previously considered expulsion from organic‐rich, mature source rocks to be very efficient. This viewpoint results from Rock‐Eval analyses of organic‐rich source rocks, analyses which demonstrate a loss of hydrocarbon (HC) generation capacity, by significant reduction in Rock‐Eval hydrogen indices, as such rocks are progressively buried in sedimentary basins. However, this progressive loss of HC generation capacity is not matched by numerically‐equivalent increases either in Soxhlet‐extractable HCs or the Rock‐Eval S1 pyrolysis peak. Thus, we conclude that almost all generated HCs have migrated from the source rocks.Notwithstanding, the petroleum geochemistry of the Williston Basin (North America) and other considerations strongly suggest that this logic may be flawed. Instead, it appears that most generated HCs may not migrate far from their generation site, but instead are lost before source‐rock samples arrive at the laboratory for analysis. This loss occurs from a HC‐gas volume expansion, which results from the large pressure decreases in rock chips or cores during the trip up the wellbore in the course of drilling operations. The large volume expansions of these HC gases, which are cogenerated and coexist with oil in the source rocks, literally blow most generated oil in source rocks into the drilling mud during the trip uphole.If most generated HCs do in fact remain in or near their source rocks, then it can be hypothesised that source rocks must be physically disrupted before meaningful expulsion can occur. Faulting, with accompanying significant fracturing, would appear to be the optimum naturally‐occurring process for physical disruption of source rocks. If these hypotheses are valid. intensity of faulting in deeply‐buried HC “kitchens” containing mature source rocks should strongly correlate with increasing basin richness, as defined by recoverable oil divided by basin‐sediment area or volume.This possible relationship is examined in this Paper; and there is a strong correlation of increasing basin richness with increasing structural intensity over and adjacent to basin depocentres. This correlation thus supports the hypothesis that physical disruption of mature source rocks is a necessary, and previously unappreciated, controlling parameter for oil expulsion. If a relationship between physical disruption of source rocks and oil expulsion indeed exists, then significant implications would follow for:(1) basin resource assessment;(2) conventional oil exploration in frontier basins; and(3) the probable existence of very large, previously unappreciated, oil‐resource bases in fractured, self‐sourced shales.

Quantitative Evaluation of Lower Cretaceous Mannville Group as Source Rock for Alberta's Oil Sands

The Western Canada sedimentary basin hosts about 12 billion bbl of conventional oil in Devonian to Cretaceous reservoirs. Lower Cretaceous oil sands contain an additional 1.3 trillion bbl in place. The oil sands represent the biodegraded remnants of supergiant conventional oil deposits, the source for which has been thought to be mature rocks of the equivalent-age Mannville Group. This work shows, however, that the known Mannville rocks alone are incapable of generating the required volume of hydrocarbons. The volume of hydrocarbons generated in the Mannville beneath central Alberta was calculated by combining measured geochemical and geologic data with Lopatin's method for thermal maturation. Original hydrocarbon-generative capacity of the Mannville rocks was calculated from geochemical analyses of immature samples. Using average values for total organic carbon (TOC) (1.3%) and Rock-Eval hydrogen index (100 mg HC/g TOC), maximum hydrocarbon generation per unit volume of source rock was calculated. The maturation model was then employed to estimate the extent to which maximum yield has actually been achieved. Total volume of source rock in the basin was obtained from isopach maps of Mannville shale. Multiplication of actual oil generation per unit volume by source rock volume gave a generated volume of 450 billion bbl. These calculated values are exceedingly optimistic, however, because they ignore inefficiencies in expulsion and migration. Inclusion of oil generated in Mannville-equivalent source rock in the Foothills belt would less than double this quantity, assuming that source potential there is similar to that of the central Alberta rocks. It is clear that the Mannville Group of the Western Canada sedimentary basin cannot be the major source of Alberta's oil-sand hydrocarbons. Either the hydrocarbons were generated in as yet undocumented, very organic-rich Mannville-equivalent rocks in the Foothills, or they are derived from multiple sources throughout the basin.

Was the Mannville Group the Source for Alberta's Heavy Oils?: ABSTRACT

The Western Canadian basin hosts about 12 billion bbl of conventional oil in Devonian to Cretaceous reservoirs. Lower Cretaceous heavy-oil sands contain 1,300 to 2,600 billion bbl in place. They represent the biodegraded remnants of supergiant conventional deposits, the source for which has been thought to be mature rocks of the equivalent-age Mannville Group. This work shows, however, that the Mannville rocks alone are incapable of generating the required volume of hydrocarbons. Volume of hydrocarbons generated in the Mannville under central Alberta was calculated by combining measured geochemical and geologic data with a model (modified from Lopatin's method) for thermal maturation. Original hydrocarbon generative capacity of the Mannville rocks was calculated from geochemical analyses of immature samples. Using average values for TOC (1.3%) and Rock-Eval Hydrogen Index (100 mg HC/g TOC), maximum hydrocarbon generation per unit volume of source rock was calculated. The maturation model was then employed to estimate the extent to which maximum yield has been achieved. Total volume of source rock in the basin was obtained from isopachs of Mannville shale. Multiplication of actual oil generation per unit volume by source rock volume gave a generated volume of 450 billion bbl. Inclusion of oil generated in the Foothills belt would less than double this number. These calculated values are exceedingly optimistic, however, because they ignore inefficiencies in expulsion and migration. It is therefore clear that the Mannville Group cannot be the major source of the heavy oils. Dominant contributions probably come from Paleozoic and other Mesozoic rocks. End_of_Article - Last_Page 610------------