The coupled generation of organic acids and hydrocarbons during source rock maturation

2020 ◽  
Author(s):  
Jian Chen ◽  
Jie Xu ◽  
Zhenyu Sun ◽  
Susu Wang ◽  
Wanglu Jia ◽  
...  
Keyword(s):  
Organic Acids ◽  
Source Rock ◽  
Maximum Yield ◽  
Source Rocks ◽  
Type I ◽  
Hydrocarbon Generation ◽  
Pore Waters ◽  
Reservoir Properties ◽  
Type Iii ◽  
Short Period

<p><strong>Introduction: </strong>Organic acids which are commonly detected in oilfield waters, can partially enhance reservoir properties. Previous studies have suggested that cleavage of the oxygen-containing functional group in kerogen is a major source of organic acids. However, this cleavage is assumed to occur before the source rock enters the oil window. If this is correct, then these acids can dissolve only minerals in the source rocks. Presently, no detailed study of the generation of organic acids during the whole thermal maturation of source rocks has been conducted. It is unclear whether organic acids could migrate into reservoirs.</p><p><strong>Aim: </strong>This research simulated the thermal evolution of source rocks in order to build a coupled model of organic acid and hydrocarbon generation, and investigate if organic acids generated in source rocks can migrate into reservoirs.</p><p><strong>Methods: </strong>Three immature source rocks containing type I, II, and III kerogens were crushed to 200 mesh. These powders, along with deionized water, were sealed in Au tubes and heated to 220–360°C for 72 h (EasyRo 0.37-1.16%). All the run products, including organic acids, gas, and bitumen, were analyzed.</p><p><strong>Results: </strong>At all temperatures, the organic acids dissolved in the waters are composed of formate, acetate, propionate, and oxalate. Acetate is the major compound with a modal proportion of >83%. The maximum yield of total organic acids was from source rocks containing type I kerogen (31.0 mg/g TOC), which was twice that from source rocks containing type II and III kerogens (13.3–15.4 mg/g TOC). However, for the type I and II kerogen-bearing source rocks, the organic acids reached a maximum yield (EasyRo = 1.16%) following the bitumen generation peak (EasyRo = 0.95%). Organic acids from type III kerogen-bearing source rocks reached their maximum yield (EasyRo = 0.95%) before the source rock entered the gas window (EasyRo > 1.16%).</p><p><strong>Conclusions: </strong>Our data suggest that the generation of organic acids is coupled with the generation of oil from type I and II kerogen-bearing source rocks, but form earlier than gas from type III kerogen-bearing source rocks. As such, some organic acids dissolved in pore waters are possibly expelled from source rocks containing type I and II kerogen with oils, which can then migrate into reservoirs. Migration of organic acids into reservoirs from source rocks containing type III kerogen is also possible in some situations. For example, when a source rock is rapidly buried for a short period, such as in the Kuqa Depression, Tarim Basin, China, the generation interval of organic acids and gas is short. Both could be expelled outside and migrate upwards into reservoirs. In conclusion, organic acids derived from source rocks can contribute to reservoir alteration.</p>

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

2020 ◽  
Vol 1 (2) ◽  
Keyword(s):  
Source Rock ◽  
Oil And Gas ◽  
Linear Regression Analysis ◽  
Sedimentary Basins ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Good Source ◽  
Type Iii ◽  
Limit Value ◽  
The Impact

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.

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.

Geochemical characterization of hydrocarbon source rocks of the Triassic-Jurassic time interval in the Mandawa basin, southern Tanzania: Implications for petroleum generation potential

2020 ◽  
Vol 123 (4) ◽  
pp. 587-596
Author(s):  
A. Emanuel ◽  
C.H. Kasanzu ◽  
M. Kagya
Keyword(s):  
Source Rocks ◽  
Geochemical Data ◽  
Time Interval ◽  
Type I ◽  
Hydrocarbon Generation ◽  
Type Ii ◽  
Geochemical Characterization ◽  
Type Iii ◽  
Petroleum Generation

Abstract Triassic to mid-Jurassic core samples of the Mandawa basin, southern Tanzania (western coast of the Indian Ocean), were geochemically analyzed in order to constrain source rock potentials and petroleum generation prospects of different stratigraphic formations within the coastal basin complex. The samples were collected from the Mihambia, Mbuo and Nondwa Formations in the basin. Geochemical characterization of source rocks intersected in exploration wells drilled between 503 to 4042 m below surface yielded highly variable organic matter contents (TOC) rated between fair and very good potential source rocks (0.5 to 8.7 wt%; mean ca. 2.3 wt%). Based on bulk geochemical data obtained in this study, the Mandawa source rocks are mainly Type I, Type II, Type III, mixed Types II/III and Type IV kerogens, with a predominance of Type II, Type III and mixed Type II/III. Based on pyrolysis data (Tmax 417 to 473oC; PI = 0.02 to 0.47; highly variable HI = 13 to 1 000 mg/gTOC; OI = 16 to 225 mg/g; and VR values of between 0.24 to 0.95% Ro) we suggest that the Triassic Mbuo Formation and possibly the mid-Jurassic Mihambia Formation have a higher potential for hydrocarbon generation than the Nondwa Formation as they are relatively thermally mature.

Petroleum Geochemistry of the Loperot-1 Well in Lokichar Basin, Kenya

2016 ◽  
Author(s):  
David M. Katithi ◽  
David O. Opar
Keyword(s):  
Organic Matter ◽  
Source Rock ◽  
Shale Gas ◽  
Source Rocks ◽  
Geochemical Data ◽  
Mature Stage ◽  
Type I ◽  
Hydrocarbon Generation ◽  
Gas Generation ◽  
Gas Targets

ABSTRACT The work reports an in-depth review of bulk and molecular geochemical data to determine the organic richness, kerogen type and thermal maturity of the Lokhone and the stratigraphically deeper Loperot shales of the Lokichar basin encountered in the Loperot-1 well. Oil-source rock correlation was also done to determine the source rocks’ likelihood as the source of oil samples obtained from the well. A combination of literature and geochemical data analyses show that both shales have good to excellent potential in terms of organic and hydrogen richness to act as conventional petroleum source rocks. The Lokhone shales have TOC values of 1.2% to 17.0% (average 5.16%) and are predominantly type I/II organic matter with HI values in the range of 116.3 – 897.2 mg/g TOC. The Lokhone source rocks were deposited in a lacustrine depositional environment in episodically oxic-dysoxic bottom waters with periodic anoxic conditions and have Tmax values in addition to biomarker signatures typical of organic matter in the mid-mature to mature stage with respect to hydrocarbon generation and immature for gas generation with Ro values of 0.51 – 0.64%. The Loperot shales were shown to be possibly highly mature type II/III source rocks with TOC values of 0.98% – 3.18% (average 2.4%), HI of 87 – 115 mg/g TOC and Ro of 1.16 – 1.33%. The Lokhone shale correlate well with the Loperot-1 well oils and hence is proposed as the principal source rock for the oils in the Lokichar basin. Although both source rocks have good organic richness to act as shale gas plays, they are insufficiently mature to act as shale gas targets but this does not preclude their potential deeper in the basin where sufficient gas window maturities might have been attained. The Lokhone shales provide a prospective shale oil play if the reservoir suitability to hydraulic fracturing can be defined. A basin wide study of the source rocks thickness, potential, maturation and expulsion histories in the Lokichar basin is recommended to better understand the present-day distribution of petroleum in the basin.

scholarly journals Source rock geochemistry of shale samples from Ege-1 and Ege-2 wells, Niger Delta, Nigeria

2020 ◽  
Author(s):  
S. L. Fadiya ◽  
S. A. Adekola ◽  
B. M. Oyebamiji ◽  
O. T. Akinsanpe
Keyword(s):  
Source Rock ◽  
Niger Delta ◽  
Source Rocks ◽  
Organic Carbon Content ◽  
Hydrocarbon Generation ◽  
Type Ii ◽  
Early Maturity ◽  
Type Iii ◽  
Niger Delta Basin ◽  
Rock Eval

AbstractSelected shale samples within the middle Miocene Agbada Formation of Ege-1 and Ege-2 wells, Niger Delta Basin, Nigeria, were evaluated using total organic carbon content (TOC) and Rock–Eval pyrolysis examination with the aim of determining their hydrocarbon potential. The results obtained reveal TOC values varying from 1.64 to 2.77 wt% with an average value of 2.29 wt% for Ege-1 well, while Ege-2 well TOC values ranged from 1.27 to 3.28 wt% (average of 2.27 wt%) values which both fall above the minimum threshold (0.5%) for hydrocarbon generation potential in the Niger Delta. Rock–Eval pyrolysis data revealed that the shale source rock samples from Ege-1 well are characterized by Type II–Type III kerogens which are thermally mature to generate oil or gas/oil. The Ege-2 well pyrolysis result showed that some of the ditch cutting samples are comprised of Type II (oil prone) and Type III (gas-prone kerogen) which are thermally immature to marginal maturity (Tmax 346–439 °C). This study concludes that the shale intercalations between reservoir sands of the Agbada Formation are good source rocks in early maturity and also must have contributed to the vast petroleum reserve in the Niger Delta Basin because of the subsidence of the basin.

scholarly journals Study on Geochemical Characteristics of tight sandstone gas accumulation in Linxing area

2020 ◽  
Vol 206 ◽  
pp. 01017
Author(s):  
Yangbing Li ◽  
Weiqiang Hu ◽  
Xin Chen ◽  
Litao Ma ◽  
Cheng Liu ◽  
...  
Keyword(s):  
Source Rock ◽  
Ordos Basin ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Light Hydrocarbons ◽  
Tight Sandstone ◽  
Source Type ◽  
Reservoir Type ◽  
Sandstone Reservoir ◽  
Main Component

Based on the comprehensive analysis of the characteristics of tight sandstone gas composition, carbon isotope, light hydrocarbons and source rocks in Linxing area of Ordos Basin, the reservoir-forming model of tight sandstone gas in this area is discussed. The study shows that methane is the main component of tight sandstone gas, with low contents of heavy hydrocarbons and non-hydrocarbons, mainly belonging to dry gas in the Upper Paleozoic in Linxing area. The values of δ13C1, δ13C2 and δ13C3 of natural gas are in the ranges of -45.6‰ ~ -32.9‰, -28.9‰ ~ -22.3‰ and -26.2‰~ -19.1‰, respectively. The carbon isotopic values of alkane gas show a general trend of positive carbon sequence. δ13C1 value is less than -30‰, with typical characteristics of organic genesis. There is a certain similarity in the composition characteristics of light hydrocarbons. The C7 series show the advantage of methylhexane, while the C5-7 series mainly shows the advantage of isoalkane. The tight sandstone gas in this area is mainly composed of mature coal-derived gas, containing a small amount of coal-derived gas and oil-type gas mixture. According to the mode of hydrocarbon generation, diffusion and migration of source rocks in Linxing area, the tight sandstone gas in the study area can be divided into three types of reservoir-forming assemblages: the upper reservoir type of the far-source type (upper Shihezi formation-shiqianfeng formation sandstone reservoir-forming away from source rocks), the upper reservoir type of the near-source type ( the Lower Shihezi formation sandstone reservoir-outside the source rock), and the self-storage type of the source type (Shanxi formation-Taiyuan formation source rock internal sand reservoir).

scholarly journals The Cambrian Henson Gletscher Formation: a mature to postmature hydrocarbon source rock sequence from North Greenland

1987 ◽  
Vol 133 ◽  
pp. 141-157
Author(s):  
F.G Christiansen ◽  
H Nøhr-Hansen ◽  
O Nykjær
Keyword(s):  
Source Rock ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Hydrocarbon Source Rock ◽  
Reservoir Rocks ◽  
Potential Source ◽  
Potential Reservoir ◽  
Field Season ◽  
North Greenland

During the 1985 field season the Cambrian Henson Gletscher Formation in central North Greenland was studied in detail with the aim of evaluating its potential as a hydrocarbon source rock. The formation contains organic rich shale and carbonate mudstone which are considered to be potential source rocks. These are sedimentologically coupled with a sequence of sandstones and coarse carbonates which might be potential reservoir rocks or migration conduits. Most of the rocks exposed on the surface are, however, thermally mature to postrnature with respect to hydrocarbon generation, leaving only few chances of finding trapped oil in the subsurface of the area studied in detail.

THE FUTURE PROSPECTIVITY OF THE PERTH BASIN

1989 ◽  
Vol 29 (1) ◽  
pp. 440 ◽  
Author(s):  
P.B. Hall
Keyword(s):  
Source Rock ◽  
Source Rocks ◽  
Northern Area ◽  
Type Iii ◽  
The Past ◽  
Recoverable Reserves ◽  
The Future ◽  
Exploration Risk ◽  
Seismic Acquisition ◽  
The Veil

The Perth Basin may have been regarded in the past as prospectively poor, but things are about to change! Seismic quality was generally poor, reservoirs often tight and source- rock maturity data limited. Abundant source rocks which tend to have a predominance of Type III kerogens have been identified and the basin has often been referred to as gas prone, the two largest discoveries having combined recoverable reserves greater than 444 billion cubic feet (12.5 Gm3).Advances in seismic acquisition and processing, available from the early 1980s, is drawing back the veil that has enveloped major areas of the basin for many years. An estimated 29 wells out of 40 exploration wells studied in the northern area of the Perth Basin were drilled off- structure. Established plays are now being correctly delineated and oil- prone source rocks with good generative potential have been identified.Perhaps the most significant occurrence in the Perth Basin was the discovery of a new play in 1987 which stimulated a new round of activity. This will undoubtedly provide economic discoveries for the participants. This renewed prospectivity will spill over into the offshore areas in the near future.The northern area of the Perth Basin has an historic exploration risk of 12.5 per cent. With future exploration risk predicted at 20- 30 per cent, this area will become one of the most prospective onshore basins in Australia.

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