Quantitative effect of kerogen type on the hydrocarbon generation potential of Paleogene lacustrine source rocks,Liaohe Western Depression,China

Kerogen types exert a decisive effect on the onset and capacity of hydrocarbon generation of source rocks.Lacustrine source rocks in the Liaohe Western Depression are characterized by thick deposition,high total organic carbon(TOC)content,various kerogen types,and a wide range of thermal maturity.Consequently,their hydrocarbon generation potential and resource estimation can be misinterpreted.In this study,geochemical tests,numerical analysis,hydrocarbon generation kinetics,and basin modeling were integrated to investigate the differential effects of kerogen types on the hydrocarbon generation potential of lacustrine source rocks.Optimized hydrocarbon generation and expulsion(HGE)models of different kerogen types were established quantitatively upon abundant Rock-Eval/TOC/vitrinite reflectance(R_(o))datasets.Three sets of good-excellent source rocks deposited in the fourth(Es4),third(Es3),and first(Es1)members of Paleogene Shahejie Formation,are predominantly types I-II_(1),II_(1)-II_(2),and II-III,respectively.The activation energy of types I-II_(2)kerogen is concentrated(180-230 kcal/mol),whereas that of type III kerogen is widely distributed(150-280 kcal/mol).The original hydrocarbon generation potentials of types I,II_(1),II_(2),and III kerogens are 790,510,270,and 85 mg/g TOC,respectively.The Ro values of the hydrocarbon generation threshold for type I-III source rocks gradually increase from 0.42%to 0.74%,and Ro values of the hydrocarbon expulsion threshold increase from 0.49%to 0.87%.Types I and II_(1)source rocks are characterized by earlier hydrocarbon generation,more rapid hydrocarbon expulsion,and narrower hydrocarbon generation windows than types II_(2)and III source rocks.The kerogen types also affect the HGE history and resource potential.Three types(conventional,tight,and shale oil/gas)and three levels(realistic,expected,and prospective)of hydrocarbon resources of different members in the Liaohe Western Depression are evaluated.Findings suggest that the Es3 member has considerable conventional and unconventional hydrocarbon resources.This study can quantitatively characterize the hydrocarbon generation potential of source rocks with different kerogen types,and facilitate a quick and accurate assessment of hydrocarbon resources,providing strategies for future oil and gas exploration.

Type Ⅰ kerogen-rich oil shale from the Democratic Republic of the Congo: mineralogical description and pyrolysis kinetics

The Democratic Republic of the Congo holds important reserves of oil shale which is still under geological status.Herein,the characterization and pyrolysis kinetics of typeⅠkerogen-rich oil shale of the western Central Kongo(CK)were investigated.X-ray diffraction,Fourier-transform infrared spectroscopy and thermal analysis(TG/DTA)showed that CK oil shale exhibits a siliceous mineral matrix with a consistent organic matter rich in aliphatic chains.The pyrolysis behavior of kerogen revealed the presence of a single mass loss between 300 and 550°C,estimated at 12.5%and attributed to the oil production stage.Non-isothermal kinetics was performed by determining the activation energy using the iterative isoconversional model-free methods and exhibits a constant value with E=211.5±4.7 kJ mol.1.The most probable kinetic model describing the kerogen pyrolysis mechanism was obtained using the Coats–Redfern and Arrhenius plot methods.The results showed a unique kinetic triplet confirming the nature of kerogen,predominantly typeⅠand reinforcing the previously reported geochemical characteristics of the CK oil shale.Besides,the calculation of thermodynamic parameters(ΔH~*,ΔS~*andΔG~*)corresponding to the pyrolysis of typeⅠkerogen revealed that the process is non-spontaneous,in agreement with DTA experiments.

Evaluation of Source Rock Potential for Hydrocarbon Generation in Shallow Offshore, Lamu Basin, Kenya

The ever-increasing demand for oil and gas has driven its exploration in rather extreme conditions. In Lamu offshore, which is hitherto underexplored, most of the wells already drilled turned out dry save for a few wells with hydrocarbon shows despite the promising reservoir properties and related geological structures. This, therefore, necessitated a source rock evaluation study in the area to ascertain the presence and potential of the source rock by integrating the geochemical data analysis and petroleum system modeling. The shallow Lamu offshore source rock quantity, quality, and maturity have been estimated through the determination of the total organic carbon (TOC) average values, Kerogen typing, and Rock-Eval pyrolysis measurements respectively. Geochemical data for Kubwa-1, Mbawa-1, Pomboo-1, and Simba-1 were evaluated for determining the source rock potential for hydrocarbon generation. Petroleum system modeling was applied in evaluating geological conditions necessary for a successful charge within a software that integrated geochemical and petrophysical characterization of the sedimentary formations in conjunction with boundary conditions that include basal heat flow, sediment-water interface temperature, and Paleo-water depth. The average TOC of 0.89 wt % in the study area suggests a fair organic richness which seems higher in the late cretaceous (0.98 wt %) than in the Paleocene (0.81 wt %). Vitrinite reflectance and Tmax values in the study area indicate the possible presence of both mature and immature source rocks. Type III Kerogen was the most dominant Kerogen type, and gas shows are the most frequent hydrocarbon encountered in the Lamu Basin with a few cases registering type II/III and type II. The charge properties (i.e. Temperature, transformation ratio, and Vitrinite reflectance) over geologic time at each of the wells have been estimated and their spatial variation mapped as seen from the burial history and depth curves overlaid with temperature, transformation ratio, and Vitrinite reflectance respectively. From the upper cretaceous maturity maps, the results seem to favor near coastal regions where average TOC is about 1.4 wt %, Vitrinite reflectance is more than 0.5%, transformation ratio is more than 10%, and temperatures range from 80°C to 160°C. The results postulate the absence of a definitive effective source rock with a likelihood of having cases of potential and possible source rocks. Moreover, greater uncertainty rests on the source rock’s presence and viability tending toward the deep offshore. Geochemical analysis and petroleum system modeling for hydrocarbon source rock evaluation improved the understanding of the occurrence of the possible and potential source rocks and processes necessary for hydrocarbon generation.

Source rock potential assessment of the Huai Hin Lat Formation,Sap Phlu Basin, Nakhon Ratchasima Province, northeastern Thailand

The Huai Hin Lat Formation has a high-potential resource, and the Ban Nong Sai part was researched and sampled. To achieve this goal, petrographic analysis(kerogen types), geochemical analysis(total organic carbon content, TOC), vitrinite reflectance(Ro), and Rock–Eval(RE) pyrolysis were carried out in this study. According to the findings, types Ⅱ, Ⅲ, and Ⅳ were identified using a modified Van-Krevelen diagram because the higher mature source rock showing hydrogen index(HI) and oxygen index(OI) are continuously depleted and raised. However,microscopic observation describes macerals as primarily sapropelic amorphinite, therefore, type I is important. The TOC was determined to be between 1.90% and 7.06%,which is considered very good to excellent. The original total organic carbon(TOCo) was decided to use its maceral components to determine how to convert extremely mature TOC to TOCo. It varies between 5.13% and 10.74% and reaches a maximum of 57.21% which is comparable to TOC. At 0.82%–1.04%, 443–451 ℃, 0.50%–38.10%, and69.00%–99.59% are the vitrinite reflectance(Ro), maximum temperature(Tmax), production index(PI), and transformation ratio(TR), respectively. Late peak maturity refers to a mixture of oil and gas, whereas most TR ratios refer to the main gas phase. Similarly, the petroleum residual shows no indication of gas trapped at a volume of6309.50 mcf/ac-ft. In summary, source rock potential was assessed within a suitable risk range defined by Tmax(445.70 ℃), Ro(0.91%), TR(90.63%), TOC(8.15%),shale thickness(46 m), and kerogen type(type I).

Spectral narratives of microstructural restyling and their controls on hydrocarbon generation potential from coal

The low to medium-rank Tertiary coals from Meghalaya,India,are explored for the first time for their comprehensive micro-structural characterization using the FTIR and Raman spectroscopy.Further,results from these coals are compared with the Permian medium and high-rank coals to understand the microstructural restyling during coalification and its controls on hydrocarbon generation.The coal samples are grouped based on the mean random vitrinite reflectance values to record the transformations in spectral attributes with increasing coal rank.The aliphatic carbon and the apparent aromaticity respond sharply to the first coalification jump(R:0.50%)during low to medium-rank transition and anchizonal metamorphism of the high-rank coals.Moreover,the Raman band intensity ratio changes during the first coalification jump but remains invari-able in the medium-rank coals and turns subtle again during the onset of pregraphitization in high-rank coals,revealing a polynomial trend with the coal metamorphism.The Rock-Eval hydrogen index and genetic potential also decline sharply at the first coalification jump.Besides,an attempt to comprehend the coal microstructural controls on the hydrocarbon poten-tial reveals that the Tertiary coals comprise highly reactive aliphatic functionalities in the type I-S kerogen,along with the low paleotemperature(74.59-112.28℃)may signify their potential to generate early-mature hydrocarbons.However,the presence of type II-II admixed kerogen,a lesser abundance of reactive moieties,and overall moderate paleotemperature(91.93-142.52℃)of the Permian medium-rank coals may imply their mixed hydrocarbon potential.Meanwhile,anchizonal metamorphism,polycondensed aromatic microstructure,and high values of paleotemperature(~334.25 to~366.79℃)of the high-rank coals indicate a negligible potential of producing any hydrocarbons.

Assessment of hydrocarbon generation potential and thermal maturity of the deep offshore Lamu Basin, Kenya

In this study, the secondary well data for Cretaceous to Miocene cutting samples in four deep offshore exploration wells, i.e., Pomboo-1 in the north, Kubwa-1 in the central, Simba-1 and Kiboko-1 in the south of the deep offshore Lamu Basin were assessed for identifying source rock presence and examining thermal maturity of the source rocks. The 2D basin modelling was used to analyse the bulk gas transformation in the basin. Total organic carbon (TOC) content values for the wells range from 0.09 wt % to 2.23 wt % with an average of 0.78 wt %. The average organic richness is higher in the Upper Cretaceous (0.83 wt %) than in the Palaeogene (0.65 wt %), Lower Cretaceous (0.28 wt %) and Upper Jurassic (0.30 wt %). The S_(1) averages for the Upper Cretaceous are 3.76 mg HC/g rock in Pomboo-1 and 0.31mg HC/g rock in Kubwa-1. The S_(2) averages for the Upper Cretaceous are 5.00 mg HC/g rock in Pomboo-1 and 0.72 mg HC/g rock in Kubwa-1. Hydrogen index (HI) values vary between 4 and 512 mg HC/g TOC with an average of 157.09 mg HC/g TOC. Organic matters were identified as mixed types of Ⅱ-Ⅲ (oil and gas prone) and Ⅲ-Ⅳ (gas prone) kerogen in the potential source rocks. The HI and S_(2) yield values are exceptionally high for the observed TOC values in Pomboo-1. The vitrinite reflectance and Tmax values of deep offshore Lamu Basin are in the ranges of 0.38%–0.72% and 360–441 ℃, respectively. It suggests the existence of both immature and mature source rocks. Vitrinite reflectance maturity favours near coastal region in the Upper Cretaceous. These results explain why Pomboo-1, Kubwa-1, Simba-1 and Kiboko-1 wells were dry. The temperatures are still cool for hydrocarbon generation in deep offshore. The critical risk for deep offshore Lamu Basin is charge, primarily source presence, and a lack of definitive evidence of a deep-water marine source rock being present. The four wells penetrate good quality reservoir and seal rocks, but source rock presence and maturity remain the critical play risk in the deep offshore Lamu Basin.

A comparative study of the specific surface area and pore structure of different shales and their kerogens

The pore structures and controlling factors of several different Paleozoic shales from Southern China and their kerogens were studied using nitrogen adsorption and scanning electron microscopy methods. The results indicate that： 1） The specific surface area is 2.22-3.52 m2/g and has no correlation with the TOC content of the Permian Dalong Formation shales, nanopores are extremely undeveloped in the Dalong Formation kerogens, which have specific surface areas of 20.35-27.49 me/g; 2） the specific surface area of the Silurian Longmaxi Formation shales is in the range of 17.83-29.49 m2/g and is positively correlated with TOC content, the kerogens from the Longmaxi Formation have well-developed nanopores, with round or elliptical shapes, and the specific surface areas of these kerogens are as high as 279.84-300.3 m2/g; 3） for the Niutitang Formation shales, the specific surface area is 20.12-29.49 m2/grock and increases significantly with increasing TOC and smectite content. The Niuti- tang Formation kerogens develop a certain amount of nanopores with a specific surface area of 161.2 m2/g. Oil shale was also examined for comparison, and was found to have a specific surface area of 19.99 m2/g. Nanopores are rare in the Youganwo Formation kerogen, which has a specific surface area of only 5.54 m2/g, suggesting that the specific surface area of oil shale is due mainly to the presence of smectite and other clay minerals. The specific surface area and the number of pores present in shales are closely related to TOC, kerogen type and maturity, smectite content, and other factors. Low-maturity kerogen has very few nanopores and therefore has a very low specific surface area, whereas nanopores are abundant in mature to over- mature kerogen, leading to high specific surface areas. The Longmaxi Formation kerogen has more developed nanopores and a higher specific surface area than the Niutitang Formation kerogen, which may be due to differences in the kerogen type and maceral components. A high content of smectite may also contribute to shale surface area. The pore volume and specific sur- face area of low-maturity kerogens are mainly attributable to pores with diameters above 10 nm. By contrast, the pore volume of mature kerogens consists predominantly of pores with diameters above 10 nm with some contribution from about 4 nm diameter pores, while the specific surface area is due mainly to pores with diameters of less than 4 nm. Through a comparative study of the specific surface area and pore structure characteristics of different shales and their kerogens, we conclude that the Longmaxi Formation shales and Niutitang Formation shales have greater sorption capacities than the Dalong Formation shales.

Evolution of pore structure in organic shale with typeⅢkerogen and high kaolinite content in Ningwu Basin

Special deposition environment makes organic-rich shales in Ningwu Basin have typeⅢkerogen and high kaolinite content,which are also famous as the kaolinite ore.The specific composition of shale in Ningwu Basin can change the pore structure and thus,influence the shale gas storage and transport.This study focuses on the pore structure and its evolution in shales with typeⅢkerogen and high kaolinite content.In this study,14 Upper Paleozoic shale samples,whose total organic matter contents(TOC)range from 0.39%to 5.91%and maturities(represented by vitrinite reflectance)range from 1.22%to 2.06%,were collected.Scanning electron microscopy(SEM),high-pressure mercury injection,and low-tempera-ture N2 adsorption experiments were used to analyze pore structure of these shale samples.Results show that when the TOC content is smaller than 1.4%,the kaolinite content decreases linearly and quartz content increases linearly with increasing the TOC content.In contrast,when TOC content is>1.4%,the clay content tends to increase with increasing TOC.Based on the SEM images,organic pores and clay pores were identified in shale samples with typeⅢkerogen and high kaolinite content.During the maturation process,the kaolinite content decreases and illite content increases with increasing the vitrinite reflectance.At the same time,the pore volume and pore surface area both increase with increasing the vitrinite reflectance,and it may be because more organic pores and clay pores in the illite were generated during the maturation process.This study can provide further understandings of shale gas accumulation in shale with typeⅢkerogen and high kaolinite content.

Characterization of Organic-Rich Shales for Petroleum Exploration & Exploitation: A Review-Part 2: Geochemistry, Thermal Maturity, Isotopes and Biomarkers

As shale exploitation is still in its infancy outside North America much research effort is being channelled into various aspects of geochemical characterization of shales to identify the most prospective basins, formations and map their petroleum generation capabilities across local, regional and basin-wide scales. The measurement of total organic carbon, distinguishing and categorizing the kerogen types in terms oil-prone versus gas-prone, and using vitrinite reflectance and Rock-Eval data to estimate thermal maturity are standard practice in the industry and applied to samples from most wellbores drilled. It is the trends of stable isotopes ratios, particularly those of carbon, the wetness ra- tio （C1/~＇（C2＋C3））, and certain chemical biomarkers that have proved to be most informative about the status of shales as a petroleum system. These data make it possible to identify production ＂sweet- spots＂, discriminate oil-, gas-liquid- and gas-prone shales from kerogen compositions and thermal ma- turities. Rollovers and reversals of ethane and propane carbon isotope ratios are particularly indica- tive of high thermal maturity exposure of an organic-rich shale. Comparisons of hopane, strerane and terpane biomarkers with vitrinite reflectance （Ro） measurements of thermal maturity highlight dis- crepancies suggesting that Ro is not always a reliable indicator of thermal maturity. Major and trace element inorganic geochemistry data and ratios provides useful information regarding provenance, paleoenvironments, and stratigraphic-layer discrimination. This review considers the data measure- ment, analysis and interpretation of techniques associated with kerogen typing, thermal maturity, sta- ble and non-stable isotopic ratios for rocks and gases derived from them, production sweet-spot identi- fication, geochemical biomarkers and inorganic chemical indicators. It also highlights uncertainties and discrepancies observed in their practical application, and the numerous outstanding questions as- sociated with them.

Identification of Hydrocarbon Potential of Talhar Shale: Member of Lower Goru Formation Using Well Logs Derived Parameters, Southern Lower Indus Basin, Pakistan

Using well logs data only, the evaluation of shale gas hydrocarbon potential of Talhar Shale Member of Lower Goru Formation has been a challenge in Southern Lower Indus Basin in Pakistan. Well logs data analysis is helpful to evaluate the gas potential of source shale rocks. We introduced and applied empirical and graphical method to fulfil this task and derived geochemical parameters from well logs data. The method mentioned is cheap and fast. Talhar Shale has kerogen type Ⅲ and type Ⅱ which are montmorillonite clay and have potential to produce oil and gas. Talhar Shale has better sorption property. Empirical formulas are used to derive parameters, using well logs of porosity, density and uranium. Porosity and volume of kerogen, calculated from density log, give average values of 11.8% and 11.4%. Average value of level of maturity index （LMI） derived from log is 0.54, which indicates that it is at the early stage of maturity. Vitrinite reflectance is between 0.5%-0.55% as calculated by graphical method and empirical formula. Talhar Shale is at onset of oil generation, with main products of oil and gas. It is a good potential source in the study area.