Hydrous Pyrolysis for Oil Production in Source Rocks: Effects of Thermal Maturity, Lithology and Experimental Conditions

2019 ◽  
Author(s):  
A.G. Kalmykov ◽  
A.Yu. Bychkov ◽  
A.V. Stennikov ◽  
M.G. Tikhonova ◽  
G.A. Kalmykov
Keyword(s):  
Oil Production ◽  
Source Rocks ◽  
Thermal Maturity ◽  
Experimental Conditions ◽  
Hydrous Pyrolysis

Complex electrical conductivity changes associated with hydrous pyrolysis maturation of the Woodford Shale

Geophysics ◽  
2017 ◽  
Vol 82 (2) ◽  
pp. D85-D106 ◽  
Author(s):  
William F. Woodruff ◽  
Michael D. Lewan ◽  
André Revil ◽  
Carlos Torres-Verdín
Keyword(s):  
Electrical Conductivity ◽  
Thermal Stress ◽  
Closed System ◽  
Thermal Stresses ◽  
Conductivity Tensor ◽  
Source Rocks ◽  
Woodford Shale ◽  
Experimental Conditions ◽  
Hydrous Pyrolysis ◽  
Complex Electrical Conductivity

Hydrous closed-system pyrolysis experiments were performed on five pairs of chert cubes from the Woodford Shale aliquots under uniaxial confinement at various prescribed thermal maturities. These thermal maturities represent each of the phases of organic-matter (OM) catagenesis under hydrous conditions: immature kerogen at low thermal stress (125°C for 72 h), low and peak bitumen generation with increasing thermal stress (300°C and 330°C for 72 h), cracking of bitumen to oil and gas at higher thermal stresses (330°C and 360°C for 72 h), and cracking of some oil at the highest experimental conditions (400°C for 72 h). We measured the spectra of the complex electrical conductivity tensor (in the frequency range 10 mHz to 45 kHz) of these 10 aliquots to capture the effects of thermal maturation by hydrous pyrolysis. Results indicate that surface conduction of polar-rich bitumens has a significant effect on their complex electrical conductivity. The OM of a source rock is considered a negligible cause of cation-exchange capacity (CEC), whose parameters influence surface and quadrature conductivity components of the complex electrical conductivity tensor. Part of this CEC was reactivated during the hydrous closed-system pyrolysis experiments. The conspicuous absence of a decrease in electrical conductivity with bitumen and oil generation in the chert cubes recovered from the hydrous-pyrolysis experiments does not agree with the observed increases of well-log resistivity in the natural maturation of some source rocks. Contraction of OM at the contacts with mineral grains is considered a partial cause of this discrepancy, which occurs during the cooling of the experiments to room temperature when no mechanical compaction is applied. Mineral-grain supported rocks such as the chert we studied appear to be especially prone to such a phenomenon.

Evidence from the Changing Carbon Isotopic of Kerogen, Oil, and Gas during Hydrous Pyrolysis from Pinghu Formation, the Xihu Sag, East China Sea Basin

Energies ◽  
2021 ◽  
Vol 14 (24) ◽  
pp. 8317
Author(s):  
Qiang Cao ◽  
Jiaren Ye ◽  
Yongchao Lu ◽  
Yang Tian ◽  
Jinshui Liu ◽  
...  
Keyword(s):  
Carbon Isotopes ◽  
Oil And Gas ◽  
Thermal Evolution ◽  
Vitrinite Reflectance ◽  
Heating Time ◽  
Source Rocks ◽  
Evolution Process ◽  
Carbon Isotopic ◽  
Hydrous Pyrolysis ◽  
Increasing Temperature

Semi-open hydrous pyrolysis experiments on coal-measure source rocks in the Xihu Sag were conducted to investigate the carbon isotope evolution of kerogen, bitumen, generated expelled oil, and gases with increasing thermal maturity. Seven corresponding experiments were conducted at 335 °C, 360 °C, 400 °C, 455 °C, 480 °C, 525 °C, and 575 °C, while other experimental factors, such as the heating time and rate, lithostatic and hydrodynamic pressures, and columnar original samples were kept the same. The results show that the simulated temperatures were positive for the measured vitrinite reflectance (Ro), with a correlation coefficient (R2) of 0.9861. With increasing temperatures, lower maturity, maturity, higher maturity, and post-maturity stages occurred at simulated temperatures (Ts) of 335–360 °C, 360–400 °C, 400–480 °C, and 480–575 °C, respectively. The increasing gas hydrocarbons with increasing temperature reflected the higher gas potential. Moreover, the carbon isotopes of kerogen, bitumen, expelled oil, and gases were associated with increased temperatures; among gases, methane was the most sensitive to maturity. Ignoring the intermediate reaction process, the thermal evolution process can be summarized as kerogen0(original) + bitumen0(original)→kerogenr (residual kerogen) + expelled oil (generated) + bitumenn+r (generated + residual) + C2+(generated + residual) + CH4(generated). Among these, bitumen, expelled oil, and C2-5 acted as reactants and products, whereas kerogen and methane were the reactants and products, respectively. Furthermore, the order of the carbon isotopes during the thermal evolution process was identified as: δ13C1 < 13C2-5 < δ13Cexpelled oil < δ13Cbitumen < δ13Ckerogen. Thus, the reaction and production mechanisms of carbon isotopes can be obtained based on their changing degree and yields in kerogen, bitumen, expelled oil, and gases. Furthermore, combining the analysis of the geochemical characteristics of the Pinghu Formation coal–oil-type gas in actual strata with these pyrolysis experiments, it was identified that this area also had substantial development potential. Therefore, this study provides theoretical support and guidance for the formation mechanism and exploration of oil and gas based on changing carbon isotopes.

Oxidation Tmax: A new thermal maturity indicator for hydrocarbon source rocks

2017 ◽  
Vol 113 ◽  
pp. 254-261 ◽  
Author(s):  
Sedat İnan ◽  
Sebastian Henderson ◽  
Salman Qathami
Keyword(s):  
Source Rocks ◽  
Thermal Maturity ◽  
Hydrocarbon Source Rocks

Liquid hydrocarbon characterization of the lacustrine Yanchang Formation, Ordos Basin, China: Organic-matter source variation and thermal maturity

2017 ◽  
Vol 5 (2) ◽  
pp. SF225-SF242 ◽  
Author(s):  
Xun Sun ◽  
Quansheng Liang ◽  
Chengfu Jiang ◽  
Daniel Enriquez ◽  
Tongwei Zhang ◽  
...  
Keyword(s):  
Organic Matter ◽  
Source Rock ◽  
Ordos Basin ◽  
Depositional Environments ◽  
Source Rocks ◽  
Type I ◽  
Hydrocarbon Generation ◽  
Type Ii ◽  
Thermal Maturity ◽  
Yanchang Formation

Source-rock samples from the Upper Triassic Yanchang Formation in the Ordos Basin of China were geochemically characterized to determine variations in depositional environments, organic-matter (OM) source, and thermal maturity. Total organic carbon (TOC) content varies from 4 wt% to 10 wt% in the Chang 7, Chang 8, and Chang 9 members — the three OM-rich shale intervals. The Chang 7 has the highest TOC and hydrogen index values, and it is considered the best source rock in the formation. Geochemical evidence indicates that the main sources of OM in the Yanchang Formation are freshwater lacustrine phytoplanktons, aquatic macrophytes, aquatic organisms, and land plants deposited under a weakly reducing to suboxic depositional environment. The elevated [Formula: see text] sterane concentration and depleted [Formula: see text] values of OM in the middle of the Chang 7 may indicate the presence of freshwater cyanobacteria blooms that corresponds to a period of maximum lake expansion. The OM deposited in deeper parts of the lake is dominated by oil-prone type I or type II kerogen or a mixture of both. The OM deposited in shallower settings is characterized by increased terrestrial input with a mixture of types II and III kerogen. These source rocks are in the oil window, with maturity increasing with burial depth. The measured solid-bitumen reflectance and calculated vitrinite reflectance from the temperature at maximum release of hydrocarbons occurs during Rock-Eval pyrolysis ([Formula: see text]) and the methylphenanthrene index (MPI-1) chemical maturity parameters range from 0.8 to [Formula: see text]. Because the thermal labilities of OM are associated with the kerogen type, the required thermal stress for oil generation from types I and II mixed kerogen has a higher and narrower range of temperature for hydrocarbon generation than that of OM dominated by type II kerogen or types II and III mixed kerogen deposited in the prodelta and delta front.

STABLE HYDROGEN ISOTOPE RATIOS OF SEDIMENTARY HYDROCARBONS: A POTENTIAL METHOD FOR ASSESSING THERMAL MATURITY?

2005 ◽  
Vol 45 (1) ◽  
pp. 253
Author(s):  
D. Dawson ◽  
K. Grice ◽  
R. Alexander
Keyword(s):  
Vitrinite Reflectance ◽  
Potential Method ◽  
Source Rocks ◽  
Crude Oils ◽  
Thermal Maturity ◽  
Peak Oil ◽  
Data Set ◽  
High Maturity ◽  
The Difference ◽  
Hydrogen Isotope Ratios

A relationship has been identified between the maturity level of source rocks and the stable hydrogen isotopic compositions (δD) of extracted saturated hydrocarbons, based on the analysis of nine sediments and five crude oils from the Perth Basin (WA). The sediments cover the immature to late mature range. Distinct δD signatures are observed for the immature sediments where pristane and phytane are significantly depleted in deuterium (D) relative to the n-alkanes. With increasing maturity the difference between the δD values of n-alkanes and isoprenoids reduces as pristane and phytane become progressively enriched in D. The n-alkane–isoprenoid δD signature of the crude oils, including one from a different source facies, is similar to mature–late mature sediments representative of the peak oil–generative window. Enrichment of D in isoprenoids is attributed to isotopic exchange associated with thermal maturation. Average δD values of pristane and phytane correlate well with vitrinite reflectance, as does the biomarker maturity parameter Ts/Tm. The limited data set suggests that δD values of aliphatic hydrocarbons may be useful for establishing thermal maturity, particularly when other maturity parameters are not appropriate. Furthermore, we suggest δD values may be useful over a wider maturity range than traditional parameters, particularly at very high maturity where biomarker parameters are no longer effective.

scholarly journals Organic geochemical and palynological studies of the Maastrichtian source rock intervals in Bida Basin, Nigeria: implications for hydrocarbon prospectivity

2020 ◽  
Vol 10 (8) ◽  
pp. 3191-3206
Author(s):  
Olusola J. Ojo ◽  
Ayoola Y. Jimoh ◽  
Juliet C. Umelo ◽  
Samuel O. Akande
Keyword(s):  
Organic Matter ◽  
Source Rock ◽  
Vitrinite Reflectance ◽  
Source Rocks ◽  
High Yield ◽  
Thermal Maturity ◽  
Hydrocarbon Source Rock ◽  
Moderate Amount ◽  
Oxic Condition ◽  
Freshwater Swamp

Abstract The Patti Formation which consists of sandstone and shale offers the best potential source beds in the Bida Basin. This inland basin is one of the basins currently being tested for hydrocarbon prospectivity in Nigeria. Fresh samples of shale from Agbaja borehole, Ahoko quarry and Geheku road cut were analysed using organic geochemical and palynological techniques to unravel their age, paleoecology, palynofacies and source bed hydrocarbon potential. Palynological data suggest Maastrichtian age for the sediments based on the abundance of microfloral assemblage; Retidiporites magdalenensis, Echitriporites trianguliformis and Buttinia andreevi. Dinocysts belonging to the Spiniferites, Deflandrea and Dinogymnium genera from some of the analysed intervals are indicative of freshwater swamp and normal sea conditions. Palynological evidence further suggests mangrove paleovegetation and humid climate. Relatively high total organic carbon TOC (0.77–8.95 wt%) was obtained for the shales which implies substantial concentration of organic matter in the source beds. Hydrocarbon source rock potential ranges from 0.19 to 0.70 mgHC/g.rock except for a certain source rock interval in the Agbaja borehole with high yield of 25.18 mgHC/g.rock. This interval also presents exceptionally high HI of 274 mgHC/g.TOC and moderate amount of amorphous organic matter. The data suggests that in spite of the favourable organic matter quantity, the thermal maturity is low as indicated by vitrinite reflectance and Tmax (0.46 to 0.48 Ro% and 413 to 475 °C, respectively). The hydrocarbon extracts show abundance of odd number alkanes C27–C33, low sterane/hopane ratio and Pr/Ph > 2. We conclude that the source rocks were terrestrially derived under oxic condition and dominated by type III kerogen. Type II organic matter with oil and gas potential is a possibility in Agbaja area of Bida Basin. Thermal maturity is low and little, or no hydrocarbon has been generated from the source rocks.

scholarly journals Effect of Kerogen Thermal Maturity on Methane Adsorption Capacity: A Molecular Modeling Approach

Molecules ◽  
2020 ◽  
Vol 25 (16) ◽  
pp. 3764 ◽  
Author(s):  
Saad Alafnan ◽  
Theis Solling ◽  
Mohamed Mahmoud
Keyword(s):  
Molecular Modeling ◽  
Adsorption Capacity ◽  
Gas Adsorption ◽  
Material Balance ◽  
Methane Adsorption ◽  
Source Rocks ◽  
Thermal Maturity ◽  
Reserve Estimation ◽  
Adsorbed Gas ◽  
Key Factor

The presence of kerogen in source rocks gives rise to a plethora of potential gas storage mechanisms. Proper estimation of the gas reserve requires knowledge of the quantities of free and adsorbed gas in rock pores and kerogen. Traditional methods of reserve estimation such as the volumetric and material balance approaches are insufficient because they do not consider both the free and adsorbed gas compartments present in kerogens. Modified versions of these equations are based on adding terms to account for hydrocarbons stored in kerogen. None of the existing models considered the effect of kerogen maturing on methane gas adsorption. In this work, a molecular modeling was employed to explore how thermal maturity impacts gas adsorption in kerogen. Four different macromolecules of kerogen were included to mimic kerogens of different maturity levels; these were folded to more closely resemble the nanoporous kerogen structures of source rocks. These structures form the basis of the modeling necessary to assess the adsorption capacity as a function of the structure. The number of double bonds plus the number and type of heteroatoms (O, S, and N) were found to influence the final configuration of the kerogen structures, and hence their capacity to host methane molecules. The degree of aromaticity increased with the maturity level within the same kerogen type. The fraction of aromaticity gives rise to the polarity. We present an empirical mathematical relationship that makes possible the estimation of the adsorption capacity of kerogen based on the degree of polarity. Variations in kerogen adsorption capacity have significant implications on the reservoir scale. The general trend obtained from the molecular modeling was found to be consistent with experimental measurements done on actual kerogen samples. Shale samples with different kerogen content and with different maturity showed that shales with immature kerogen have small methane adsorption capacity compared to shales with mature kerogen. In this study, it is shown for the first time that the key factor to control natural gas adsorption is the kerogen maturity not the kerogen content.

scholarly journals Worldwide shale-oil reserves: towards a global approach based on the principles of Petroleum System and the Petroleum System Yield

2017 ◽  
Vol 188 (5) ◽  
pp. 33 ◽  
Author(s):  
Marc Blaizot
Keyword(s):  
Middle East ◽  
Source Rock ◽  
Oil Production ◽  
Petroleum System ◽  
Source Rocks ◽  
Recovery Factor ◽  
Shale Oil ◽  
Average Recovery ◽  
Oil Reserves ◽  
Oil Resources

Global inventory of shale-oil resources and reserves are far from being complete even in mature basins which have been intensively drilled and produced and in which the main parameters of the regional or local oil-prone source rocks are known. But even in these cases, difficulties still occur for deriving reserves from resources: reaching a plausible recovery factor is actually a complex task because of the lack of production history in many shale-oil ventures. This exercise is in progress in several institutions (EIA, USGS, AAPG) or private oil and gas companies on a basin-by-basin basis in order to estimate the global potential. This analytical method is very useful and accurate but also very time consuming. In the last EIA report in 2013 “only” 95 basins had been surveyed whereas for example, no Middle-East or Caspian basins have been taken into account. In order to accelerate the process and to reach an order of magnitude of worldwide shale-oil reserves, we propose hereafter a method based on the Petroleum System principle as defined by Demaison and Huizinga (Demaison G and Huizinga B. 1991. Genetic classification of Petroleum Systems. AAPG Bulletin 75 (10): 1626–1643) and more precisely on the Petroleum System Yield (PSY) defined as the ratio (at a source-rock drainage area scale) between the accumulated hydrocarbons in conventional traps (HCA) and hydrocarbons generated by the mature parts of the source-rock (HCG). By knowing the initial oil reserves worldwide we can first derive the global HCA and then the HCG. Using a proxy for amount of the migrated oil from the source-rocks to the trap, one can obtain the retained accumulations within the shales and then their reserves by using assumptions about a possible average recovery factor for shale-oil. As a definition of shale-oil or more precisely LTO (light tight oil), we will follow Jarvie (Jarvie D. 2012. Shale resource systems for oil & gas: part 2 – Shale Oil Resources Systems. In: Breyer J, ed. Shale Reservoirs. AAPG, Memoir 97, pp. 89–119) stating that “shale-oil is oil stored in organic rich intervals (the source rock itself) or migrated into juxtaposed organic lean intervals”. According to several institutes or companies, the worldwide initial recoverable oil reserves should reach around 3000 Gbo, taking into account the already produced oil (1000 Gbo) and the “Yet to Find” oil (500 Gbo). Following a review of more than 50 basins within different geodynamical contexts, the world average PSY value is around 5% except for very special Extra Heavy Oils (EHO) belts like the Orinoco or Alberta foreland basins where PSY can reach 50% (!) because large part of the migrated oils have been trapped and preserved and not destroyed by oxidation as it is so often the case. This 50% PSY figure is here considered as a good proxy for the global amount of expelled and migrated oil as compared to the HCG. Confirmation of such figures can also be achieved when studying the ratio of S1 (in-place hydrocarbon) versus S2 (potential hydrocarbons to be produced) of some source rocks in Rock-Eval laboratory measurements. Using 3000 Gbo as worldwide oil reserves and assuming a quite optimistic average recovery factor of 40%, the corresponding HCA is close to 7500 Gbo and HCG (= HCA/PSY) close to 150 000 Gbo. Assuming a 50% expulsion (migration) factor, we obtain that 75 000 Gbo is trapped in source-rocks worldwide which corresponds to the shale-oil resources. To derive the (recoverable) reserves from these resources, one needs to estimate an average recovery factor (RF). Main parameters for determining recovery factors are reasonable values of porosity and saturation which is difficult to obtain in these extremely fine-grained, tight unconventional reservoirs associated with sampling and laboratories technical workflows which vary significantly. However, new logging technologies (NMR) as well as SEM images reveal that the main effective porosity in oil-shales is created, thanks to maturity increase, within the organic matter itself. Accordingly, porosity is increasing with Total Organic Carbon (TOC) and paradoxically with… burial! Moreover, porosity has never been water bearing, is mainly oil-wet and therefore oil saturation is very high, measured and calculated between 75 and 90%. Indirect validation of such high figures can be obtained when looking at the first vertical producing wells in the Bakken LTO before hydraulic fracturing started which show a very low water-cut (between 1 and 4%) up to a cumulative oil production of 300 Kbo. One can therefore assume that the highest RF values of around 10% should be used, as proposed by several researchers. Accordingly, the worldwide un-risked shale-oil reserves should be around 7500 Gbo. However, a high risk factor should be applied to some subsurface pitfalls (basins with mainly dispersed type III kerogen source-rocks or source rocks located in the gas window) and to many surface hurdles caused by human activities (farming, housing, transportation lines, etc…) which can hamper developments of shale-oil production. Assuming that only shale-oil basins in (semi) desert conditions (i.e., mainly parts of Middle East, Kazakstan, West Siberia, North Africa, West China, West Argentina, West USA and Canada, Mexico and Australia) will be developed, a probability factor of 20% can be used. Accordingly, the global shale-oil reserves could reach 1500 Gbo which is half the initial conventional reserves and could therefore double the present conventional oil remaining reserves.

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