Source Rock For Oil Generation Research Articles

Seismic Reflection Profiles Reveal the Ore-Controlling Structures of Carlin-Style Gold Deposits in Lannigou Gold Fields, Southwestern Guizhou, China

AbstractThe Carlin-style Lannigou gold deposit is hosted in Triassic flysch in the Nanpanjiang basin in southwestern Guizhou Province, southern China. This study is the first to use seismic exploration data to elucidate the structural architecture of the Lannigou Carlin-style gold deposit. We use regional seismic reflection data to show that gold orebodies are controlled by faults that link with the regional Lannigou-Weihuai fault, and we use this new insight to determine the relationship between mineralization and inverted basin faults to constrain the structural controls of this gold system.A grid of seven seismic sections covering the Lannigou gold fields is combined with field geologic data to reveal two distinct structural patterns. Seismic data reveals that the inverted, E-dipping Lannigou-Weihuai fault is shallowly penetrating (less than 2 km) in the north and increasingly penetrates the pre-Devonian basement rocks to the south, where the fault can be imaged to depths greater than 5 to 7 km. Basement-penetrating faults link the metamorphic basement and overlying basin successions that include potential source rocks for oil generation, interpreted gas reservoirs, and gold deposits. Therefore, these deep-seated faults are important channels for the migration of ore fluids, especially for the transport of hydrocarbon gas, which may have served as an important chemical trap for gold mineralization.Seismic data also reveals the W-dipping Qiaoluo fault that bounds the inverted Qiaoluo half-graben. Fault crosscutting relationships reveal an extensional episode from the Late Paleozoic to the early Anisian age of the Middle Triassic epoch (i.e., the depositional age of the second member of the Middle Triassic Xuman Formation), which is overprinted by an episode of middle Anisian basin inversion during deposition of the third member of the Xuman Formation. This inversion occurred at ca. 248 to 246 Ma. Based on the ore-controlling constraints and previous geochronological data, we consider that the Lannigou gold deposit was formed in the Late Triassic to Early Jurassic during syndepositional inversion of existing basement-penetrating basinal faults in a foreland basin. The first-order faults in the above structural belts, such as the Lannigou-Weihuai fault and the blind Qiaoluo fault, are most favorable targets for further exploration of undiscovered gold orebodies. This study demonstrates that seismic reflection is a powerful tool to reveal deep structures at varying scales from mineral deposits to sedimentary basins.

Beaufort–Mackenzie Tectono-Sedimentary Element

Abstract The Beaufort–Mackenzie Tectono-Sedimentary Element (TSE) is a post-rift sequence of the Canada Basin that consists of Late Cretaceous–Pleistocene sedimentary strata with a maximum thickness of over 12 km. The tectonics of the Canada Basin formation and the Cenozoic contractional deformation associated with the Cordilleran Orogeny jointly shaped and controlled the architecture and the depositional systems of the TSE. In the west, contractional deformation prevails, whereas in the east extensional deformation dominates, and gravitational deformation associated with growth faults is prominent in the far north. Early successions of Cenomanian–Early Maastrichtian age are composed of thin but commonly organic-rich muds (Boundary Creek, Smoking Hills and Mason River sequences) that were deposited on the continental margin. The main phase of sedimentation started in the Late Maastrichtian with the deposition of a series of large progradational delta complexes, which migrated oceanwards from the SW margin in the Paleogene to the central part of the TSE in the Pliocene in response to the rising Cordilleran orogen in the SW. Coal seams and gas-prone terrestrial-derived organic-rich interbeds in the Cenozoic sequences are the main source rocks for gas generation, whereas organic-rich marine shales in Cretaceous sequences are probably the source rocks for oil generation. The Beaufort–Mackenzie TSE is a proven petroleum province with many significant discoveries and a large undiscovered resource potential in oil, gas and methane hydrate.

GEOCHEMICAL AND GEOSTATISTICAL ASSESSMENT OF CRETACEOUS COALS AND SHALES IN SOME NIGERAIN SEDIMENTARY BASINS FOR THEIR HYDROCARBON PRONESS AND MATURITY LEVELS

The Rock–Eval pyrolysis and LECO analysis for 9 shale and 12 coal samples, as well as, geostatistical analysis have been used to investigate source rock characteristics, correlation between the assessed parameters (QI, BI, S1, S2, S3, HI, S1 + S2, OI, PI, TOC) and the impact of changes in the Tmax on the assessed parameters in the Cretaceous Sokoto, Anambra Basins and Middle Benue Trough of northwestern, southeastern and northcentral Nigeria respectively. The geochemical results point that about 97% of the samples have TOC values greater than the minimum limit value (0.5 wt %) required to induce hydrocarbon generation from source rocks. Meanwhile, the Dukamaje and Taloka shales and Lafia/Obi coal are found to be fair to good source rock for oil generation with slightly higher thermal maturation. The source rocks are generally immature through sub-mature to marginal mature with respect to the oil and gas window, while the potential source rocks from the Anambra Basin are generally sub-mature grading to mature within the oil window. The analyzed data were approached statistically to find some relations such as factors, and clusters concerning the examination of the source rocks. These factors were categorized into type of organic matter and organic richness, thermal maturity and hydrocarbon potency. In addendum, cluster analysis separated the source rocks in the study area into two groups. The source rocks characterized by HI >240 (mg/g), TOC from 58.89 to 66.43 wt %, S1 from 2.01 to 2.54 (mg/g) and S2 from 148.94 to 162.52 (mg/g) indicating good to excellent source rocks with kerogen of type II and type III and are capable of generating oil and gas. Followed by the Source rocks characterized by HI <240 (mg/g), TOC from 0.94 to 36.12 wt%, S1 from 0.14 to 0.72 (mg/g) and S2 from 0.14 to 20.38 (mg/g) indicating poor to good source rocks with kerogen of type III and are capable of generating gas. Howeverr, Pearson’s correlation coefficient and linear regression analysis shows a significant positive correlation between TOC and S1, S2 and HI and no correlation between TOC and Tmax, highly negative correlation between TOC and OI and no correlation between Tmax and HI. Keywords- Cretaceous, Geochemical, Statistical, Cluster; Factor analyses.

Integrated Geochemical and Multivariate Statistical Examination of Source Rocks in the Sokoto and Anambra Basins, Nigeria: Implications for Hydrocarbon Prospectivity

The LECO and Rock–Eval pyrolysis for 7 shale and 3 coal samples, as well as, multivariate statistical analysis have been used to probe source rock characteristics, correlation between the assessed parameters (S1, S2, S3, HI, S1 + S2, OI, PI, TOC) and the impact of changes in the Tmax on the assessed parameters in the Sokoto Basin and Anambra Basin of northwestern and southeastern Nigeria respectively. The geochemical results show that 93% of the samples have TOC values greater than the minimum limit value (0.5 wt %) required to induce hydrocarbon generation from source rocks. Meanwhile, the Dukamaje and Taloka shales are found to be fair to good source rock for oil generation with slightly higher thermal maturation. The source rocks are generally immature through sub-mature to marginal mature with respect to the oil and gas window, while the potential source rocks from the Anambra Basin are generally sub-mature grading to mature within the oil window. The analyzed data were approached statistically to find some relations such as factors, and clusters concerning the examination of the source rocks. These factors were categorized into type of organic matter and organic richness, thermal maturity and hydrocarbon potency. In addendum, cluster analysis separated the source rocks in the study area into two groups. The source rocks characterized by HI >240 (mg/g), TOC from 58.89 to 66.43 wt%, S1 from 2.01 to 2.54 (mg/g) and S2 from 148.94 to 162.52 (mg/g) indicating good to excellent source rocks with kerogen of type II and type III and are capable of generating oil and gas. Followed by the Source rocks characterized by HI <240 (mg/g), TOC from 0.94 to 6.68 wt%, S1 from 0.14 to 0.72 (mg/g) and S2 from 0.14 to 3.36 (mg/g) indicating poor to good source rocks with kerogen of type III and are capable of generating gas. Howeverr, Pearson’s correlation coefficient and linear regression analysis shows a significant positive correlation between TOC and S1, S2 and HI and no correlation between TOC and Tmax, highly negative correlation between TOC and OI and no correlation between Tmax and HI.

Delineation of factors that control hydrocarbon source rock maturity in Anambra and Abakaliki Basins South-Eastern Nigeria

Outcrop information from Abakaliki and Anambra were used in this study to characterize the source and reservoir rocks in the two basins in order to give indication(s) for hydrocarbon generation potential in the basins to minimize uncertainty and risk that are allied with exploration and field development of oil and gas. Outrop mapping method was used to carry out geological, stratigraphical, geochemical, structural, petrographical, and sedimentological studies of rock units from outcrop sections within the two basins. Thirty-eight samples of shale were collected fromthese Basins in stratified mode of random sampling, and geochemical analysis (rockeval) was performed on the samples to determine the total organic content (TOC) and to assess the oil generating window. The results were analyzed, to properly characterize the potential source rock(s) and reservoir rock(s) in the basins, and factor(s) that can favour hydrocarbon traps. The results of the geological, stratigraphical, sedimentological, geochemical, and structural mapping were used to develop a new model for hydrocarbon generation in the Basins. The result of the geochemical analysis of shale samples from the Anambra Basin shows that the TOC values are ≥𝟏𝒘𝒕%, Tmax ≥𝟒𝟑𝟏℃, Vitrinite reflectance values are ≥𝟎.𝟔%, and S1+S2 values are >𝟐.𝟓𝒎𝒈/𝒈 for Mamu Formation while shale samples from other formations within Anambra Basin fall out of these ranges. The shale unit in the Mamu Formation is the major source rock for oil generation in the Anambra Basin while others have potential for gas generation with very little oil generation. The shale samples from Abakaliki Basin show that S 1 +S 2 values range from <𝟏−𝟐𝟎𝒎𝒈/𝒈, TOC values range from 0.31-4.55wt%, vitrinite reflectance ranges from 0.41-1.24% and Tmax ranges from 𝟒𝟐𝟑℃−𝟒𝟔𝟔℃. This result also shows that there is no source rock for oil generation in Abakaliki Basin; it is either gas or graphite. Keywords: Source rock, kerogen type, Abakaliki Basin, Anambra Basin, Oil generating window

Multivariate geochemical and statistical methods applied to assessment of organic matter potentiality and its correlation with hydrocarbon maturity parameters (Case study: Safir-1x well, North Western Desert, Egypt)

The TOC-Rock–Eval pyrolysis and vitrinite reflectance measurements for “15” shale rock samples, as well as, multivariate statistical analysis are discussed to investigate hydrocarbon, source rock characteristics, correlation between the assessed parameters (S1, S2, HI, S1+S2, QI, BI, PI, TOC) and the impact of changes in the Tmax and Ro% on the assessed parameters in Safir exploratory-1x well in Safir oilfield. The geochemical analysis indicated that the Bahariya Formation is considered to be a poor source rock for oil generation with a low degree of thermal maturation in comparison with the Alam El Bueib and Khatatba Formations. However, Alam El Bueib is found to be a good source rock for oil generation with slightly higher thermal maturation. Interestingly, Khatatba Formation lies within the oil and gas generation window and shows an excellent source rock potential. Based on statistical findings of cluster and factor analysis, the source rocks in the study area are classified into two types corresponding to two different clusters. Cluster I includes Alam El Bueib and characterized by kerogen type II and II/III whereas, cluster II, characterized by kerogen type III, is subdivided into two subgroups (IIa and IIb) and represents Bahariya and Khatatba source rocks. Nonparametric tests (K-independent samples) between the dataset of 15 samples confirm that the distribution of values from respective parameters exhibits significant difference (P<0.05) except for PI and BI. On the other hand, the nonparametric tests (2-independent samples) showed that there is no significant difference (P>0.05) in the distribution of HI and QI values indicating that both HI and QI values remain constant with increasing thermal maturity. Unlike TOC and HI, Pearson’s and linear regression analysis indicated a significant correlation between TOC and S2. Nevertheless, two different trends were observed between S1 and S2. Moreover, the Ro% and Tmax were found to be positively correlated. Interestingly, our study showed no significant correlation between HI, QI, BI and thermal maturity (Ro% and Tmax), while, a good correlation between TOC, S2 and thermal maturity was observed.

Late Cretaceous paleoenvironment and lake level fluctuation in the Songliao Basin, northeastern China

AbstractStudy of Late Cretaceous lacustrine sedimentary strata in the eastern Songliao Basin, China revealed that the paleoclimate was relatively arid and hot during sedimentation of the upper Santonian of the Yaojia Formation, but became relatively humid and warm during deposition of the lower Campanian Nenjiang Formation. The upper Yaojia Formation was deposited in a freshwater lake environment, while the lower Nenjiang Formation was deposited in a slightly brackish to brackish environment. The average total organic carbon content in the upper Yaojia Formation is 0.15%, while the hydrogen index is 36 mgHC/gTOC, implying poor source rock for oil generation and the organic matter comprised of a mixture of woody and herbaceous organic matter. In contrast, the hydrogen index of oil shale and black shale of the lower Nenjiang Formation is 619 mgHC/gTOC, and total organic carbon content on average is 3.37%, indicating a mixed algae and herbaceous source of kerogen and an increase in aquatic bioproductivity. The black shale and oil shale have low Pristane/Phytane and C29 5α,14α,17α(H) − stigmastane 20R/(20R + 20S) ratios, with maximum concentration of n‐alkanes at n‐C23, implying an anoxic depositional environment with algae, bacteria and higher plants providing most of the organic matter. Relatively abundant gammacerane and a higher Sr/Ba ratio in the oil shales suggest the presence of brackish water and development of salinity stratification in the lake. During sedimentation of the upper Yaojia through the lower Nenjiang Formations, the level of Songliao lake increased and a deep‐lake environment was formed with bottom waters being oxygen depleted. Concomitantly, as the lake deepened bottom conditions were changing from oxic to anoxic, and the input of organic matter changed from predominantly higher plants to a mixture of bacteria, algae and higher plants providing favorable conditions for oil source rock accumulation.

The indigenous origin of Witwatersrand “carbon”

In the Witwatersrand approximately 40% of the gold is intimately associated with so-called “carbon” in “carbon seam reefs”, which occur in over a dozen paleoplacers, many of them concentrated at two stratigraphic levels in the 7000-m-thick succession of Archean siliciclastic sedimentary rocks. This is reduced carbon, present as kerogen admixed in various proportions with derivative (now solid) bitumen(s). Oil generation and migration were active geological processes during Early Earth history. Numerous possible source rocks for oil generation, including the carbon seams themselves, occur within the Witwatersrand basin. In the Witwatersrand ore, oil-bearing fluid inclusions are also present, derived like the bitumen, by thermal maturation of the kerogen. The presence of kerogen and bitumen in the Witwatersrand sedimentary rocks, together with a wealth of observations on the spatial distribution of the carbon seams confirm that the carbon originated in situ from living organisms in microbial mat cover, as opposed to flowing in from elsewhere as liquid hydrocarbons as some researchers have suggested. Paleochannels, which truncated auriferous carbon seams early in the depositional history, are of widespread occurrence, and micro-synsedimentary faults offset carbon seams. The carbon seams are thus indigenous biogenic markers that grew contemporaneously with placer development. The various features highlighting the nature and spatial distribution of Witwatersrand carbon seams provide a classic case where field evidence trumps laboratory data in the reconstruction of geological processes.

The Hydrocarbon Potential of Miocene Source Rocks for Oil Generation in the South Gulf of Suez, Egypt

Sixteen cutting and four core samples, in addition two crude oil samples are representative for the Miocene source rocks and reservoirs in some wells in the southern part of Gulf of Suez. These samples were subjected to advanced geochemical tools (pyrolysis, elemental analyses, gas chromatography, and gas chromatography-mass spectrometry). In addition, burial history model of the deepest well is recognized. The results showed that the Middle-Upper Miocene source rocks are immature, originated mainly from mixed organic sources, have poor to fair potentiality to produce oil, and did not reach the early stage of hydrocarbon generation until the present time. Lower Miocene source rocks are mature, derived from marine organic sources, have good potential to generate oil and gas, and entered the early stage of hydrocarbon generation and oil window till present time. The crude oil samples are mature, originated mainly from marine sources, and show good correlation with the Lower Miocene source rocks. Therefore, the Lower Miocene source rocks may be considered an effective source for oil generation in the southern part of Gulf of Suez.