Tectonic Control in Source Rock Maturation and Oil Migration in Trinidad and Implications for Petroleum Exploration

1992 ◽  
pp. 237-249 ◽  
Author(s):  
KRISHNA M. PERSAD ◽  
SUHAS C. TALUKDAR ◽  
WALLACE G. DOW
Keyword(s):  
Source Rock ◽  
Petroleum Exploration ◽  
Oil Migration ◽  
Tectonic Control

scholarly journals Oil chemometrics and geochemical correlation in the Weixinan Sag, Beibuwan Basin, South China Sea

2020 ◽  
Vol 38 (6) ◽  
pp. 2695-2710
Author(s):  
Yao-Ping Wang ◽  
Xin Zhan ◽  
Tao Luo ◽  
Yuan Gao ◽  
Jia Xia ◽  
...  
Keyword(s):  
Source Rock ◽  
Principal Component ◽  
Sedimentary Basins ◽  
Oil Field ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
Crude Oils ◽  
Geochemical Parameters ◽  
Group I ◽  
Oil Source

The oil–oil and oil–source rock correlations, also termed as geochemical correlations, play an essential role in the construction of petroleum systems, guidance of petroleum exploration, and definition of reservoir compartments. In this study, the problems arising from oil–oil and oil–source rock correlations were investigated using chemometric methods on oil and source rock samples from the WZ12 oil field in the Weixinan sag in the Beibuwan Basin. Crude oil from the WZ12 oil field can be classified into two genetic families: group A and B, using multidimensional scaling and principal component analysis. Similarly, source rocks of the Liushagang Formation, including its first, second, and third members, can be classified into group I and II, corresponding to group B and A crude oils, respectively. The principle geochemical parameters in the geochemical correlation for the characterisation and classification of crude oils and source rocks were 4MSI, C27Dia/C27S, and C24 Tet/C26 TT. This study provides insights into the selection of appropriate geochemical parameters for oil–oil and oil–source rock correlations, which can also be applied to other sedimentary basins.

The transformation effect of source rock-derived acidic fluid on carbonate reservoir from simulation experiments

2020 ◽  
Author(s):  
Qian Ding ◽  
Zhiliang He ◽  
Dongya Zhu
Keyword(s):  
Physical Properties ◽  
Source Rock ◽  
Carbonate Reservoir ◽  
Carbonate Reservoirs ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
Hydrocarbon Generation ◽  
High Quality ◽  
Simulation Experiments ◽  
Deep Layers

<p>Deep and ultra-deep carbonate reservoir is an important area of petroleum exploration. However, the prerequisite for predicting high quality deep ultra-deep carbonate reservoirs lays on the mechanism of carbonate dissolution/precipitation. It is optimal to perform hydrocarbon generation-dissolution simulation experiments to clarify if burial dissolution could improve the physical properties of carbonate reservoirs, while quantitatively and qualitatively describe the co-evolution process of source rock and carbonate reservoirs in deep layers. In this study, a series of experiments were conducted with the limestone from the Ordovician Yingshan Formation in the Tarim Basin, and the low maturity source rock from Yunnan Luquan, with a self-designed hydrocarbon generation-dissolution simulation equipment. The controlling factors accounted for the alteration of carbonate reservoirs and dissolution modification process by hydrocarbon cracking fluid under deep burial environments were investigated by petrographic and geochemical analytical methods. In the meantime, the transformation mechanism of surrounding rocks in carbonate reservoirs during hydrocarbon generation process of source rock was explored. The results showed that: in the burial stage, organic acid, CO<sub>2</sub> and other acidic fluids associated with thermal evolution of deep source rocks could dissolve carbonate reservoirs, expand pore space, and improve porosity. Dissolution would decrease with the increasing burial depth. Whether the fluid could improve reservoir physical properties largely depends on calcium carbonate saturation, fluid velocity, water/rock ratio, original pore structure etc. This study could further contribute to the prediction of high-quality carbonate reservoirs in deep and ultra-deep layers.</p>

scholarly journals Dinoflagellate biostratigraphy of Eastern Indonesia stratigraphy: key of petroleum exploration success

2021 ◽  
Vol 47 (3) ◽  
pp. 75-76
Author(s):  
Herman Darman
Keyword(s):  
Source Rock ◽  
Significant Role ◽  
Petroleum System ◽  
Petroleum Exploration ◽  
Marine Biota ◽  
Eastern Indonesia ◽  
Continental Plate ◽  
Sandstone Provenance

Several major discoveries in the eastern part of Indonesia (e.g. Tangguh and Abadi) have increased more petroleum exploration interest in the area. These sizeable discoveries encountered gas in the Jurassic sandstone, which is a key reservoir target in the Northwest Shelf of Australia. The Mesozoic sandstone provenance is located in the Australian Continental Plate or also known as the Sahul Shelf. Thousands of wells were drilled in the Sahul Shelf and the stratigraphy in this area is well understood. The extension of the Mesozoic sandstone towards Indonesian territory, with much less well information, is one of the keys of success for petroleum exploration. Refinement of the stratigraphy of the eastern part of Indonesia is crucial to understand the extension.To refine the stratigraphy of Eastern Indonesia, especially for the Mesozoic interval, dinoflagellates play a significant role. Several types of this marine biota have been used by Australian stratigraphers as markers. In the case where stratigraphic tie to Northwest Shelf Australia discoveries, key wells or standard chronostratigraphy, dinoflagellate understanding is critical.Dinoflagellate markers are used to mark several subdivisions of Plover Sandstone. Norvick (2001) used W. indotata and D. caddaensis Maximum Flooding Surfaces to subdivide the reservoir target into upper, middle and lower Plover Formation. These surfaces are named after dinoflagellates. More markers were identified to mark the source rock and seal in the petroleum system. To have a detail correlation from Indonesia to the NW Shelf, understanding of dinoflagellates is crucial. 

A NEW PERSPECTIVE ON EXPLORING THE COOPER/EROMANGA PETROLEUM PROVINCE—EVIDENCE OF OIL CHARGING FROM THE WARBURTON BASIN

2006 ◽  
Vol 46 (1) ◽  
pp. 261 ◽  
Author(s):  
C.O.E. Hallmann ◽  
K.R. Arouri ◽  
D.M. McKirdy ◽  
L. Schwark
Keyword(s):  
Source Rock ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
True Nature ◽  
Hydrocarbon Biomarkers ◽  
Source Signal ◽  
History Of ◽  
Permian Coal ◽  
New Perspective ◽  
Rock Eval

The history of petroleum exploration in central Australia has been enlivened by vigorous debate about the source(s) of the oil and condensate found in the Cooper/Eromanga basin couplet. While early workers quickly recognized the source potential of thick Permian coal seams in the Patchawarra and Toolachee Formations, it took some time for the Jurassic Birkhead Formation and the Cretaceous Murta Formation to become accepted as effective source rocks. Although initially an exploration target, the Cambrian sediments of the underlying Warburton Basin subsequently were never seriously considered to have participated in the oil play, possibly due to a lack of subsurface information as a consequence of limited penetration by only a few widely spaced wells. Dismissal of the Warburton sequence as a source of hydrocarbons was based on its low generative potential as measured by total organic carbon (TOC) and Rock-Eval pyrolysis analyses. As most of the core samples analysed came from the upper part of the basin succession that has been subjected to severe weathering and oxidation, these results might not reflect the true nature of the Warburton Basin’s source rocks. We analysed a suite of source rock extracts, DST oils and sequentially extracted reservoir bitumens from the Gidgealpa field for conventional hydrocarbon biomarkers as well as nitrogen-containing carbazoles. The resulting data show that organic facies is the main control on the distribution of alkylated carbazoles in source rock extracts, oils and sequentially extracted bitumens. The distribution pattern of alkylcarbazoles allows to distinguish between rocks of Jurassic, Permian and pre-Permian age, thereby exceeding the specificity of hydrocarbon biomarkers. While no pre-Permian signature can be found in the DST oils, it is present in sequentially extracted residual oils. However, the pre-Permian molecular source signal is diluted beyond recognition during conventional extraction procedures. The bitumens that are characterised by a pre-Permian geochemical signature derive from differing pore-filling oil pulses and exhibit calculated maturities of up to 1.6% Rc, thereby proving for the first time the petroleum generative capability of source rocks in the Warburton Basin.

THE PETROLEUM PROSPECTIVITY OF THE CLARENCE-MORETON BASIN IN NEW SOUTH WALES

1985 ◽  
Vol 25 (1) ◽  
pp. 15
Author(s):  
P. Ties ◽  
R.D. Shaw ◽  
G.C. Geary
Keyword(s):  
Source Rock ◽  
Seismic Data ◽  
New South ◽  
New South Wales ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
South Wales ◽  
Oil Generation ◽  
Single Fold ◽  
Coal Measures

The Clarence-Moreton Basin covers an area of some 28 000 km2 in north-eastern New South Wales and south-eastern Queensland. The basin is relatively unexplored, with a well density in New South Wales of one per 1600 km2. Since 1980, Endeavour Resources and its co-venturers have pursued an active exploration programme which has resulted in the recognition of significant petroleum potential in the New South Wales portion of the basin.Previous studies indicated that the Upper Triassic to Lower Cretaceous Clarence-Moreton Basin sequence in general, lacked suitable reservoirs and had poor source- rock potential. While exinite rich, oil-prone source rocks were recognised in the Middle Jurassic Walloon Coal Measures, they were considered immature for oil generation. Moreover, during the 1960's the basin acquired a reputation as an area where seismic records were of poor quality.These ideas are now challenged following the results of a new round of exploration which commenced in the New South Wales portion of the basin in 1980. This exploration has involved the acquisition of over 1000 km of multifold seismic data, the reprocessing of some 200 km of existing single fold data, and the drilling of one wildcat well. Over twenty large structural leads have been identified, involving trapping mechanisms ranging from simple drape to antithetic and synthetic fault blocks associated with normal and reverse fault dependent and independent closures.The primary exploration targets in the Clarence- Moreton Basin sequence are Lower Jurassic sediments comprising a thick, porous and permeable sandstone unit in the Bundamba Group, and channel and point-bar sands in the Marburg Formation. Source rocks in these and the underlying Triassic coal measures are gas-prone and lie at maturity levels compatible with gas generation. In contrast, it was established from the results of Shannon 1 that the Walloon Coal Measures are mature for oil generation and this maturity regime is now considered to be applicable to most of the basin in New South Wales.A consideration of reservoir and source rock distribution, together with structural trends across the basin in Petroleum Exploration Licences 258 and 259, has led to the identification of three prospective fairways, two of which involve shallow oil plays. Exploration of these fairways is currently the focus of an ongoing programme of further seismic data acquisition and drilling.

Maturity Evolution of the Cambrian Source Rocks in the Tarim Basin

2012 ◽  
Vol 622-623 ◽  
pp. 1642-1645
Author(s):  
Zong Lin Xiao ◽  
Qing Qing Hao ◽  
Zhong Min Shen
Keyword(s):  
Source Rock ◽  
Tarim Basin ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
Mature Stage ◽  
Hydrocarbon Generation ◽  
Foreland Basins ◽  
Structural History ◽  
Depositional Age ◽  
Petroleum Basin

The Tarim basin is an important petroleum basin in China, and the Cambrian strata are the major source rock successions in the basin. Integrated the source rock depositional and structural history with its geochemical and thermal parameters, this paper simulates the evolution of the Cambrian source rocks with the software Basinview. The simulation result shows that the main hydrocarbon-generation centers of the Manjiaer sag in the Tabei depression and the Tangguzibasi sag in the Southwest depression are characterized by their early hydrocarbon generation, and in the late Ordovician depositional age, they reached dry gas stage. The Kuqa and Southwest depressions developed in the Cenozoic foreland basins made the Cambrian source rocks mature rapidly in the Cenozoic period. The source rock maturity in the Tarim basin now is characterized by high in the east and west and low in the middle, and most of the area is in the over-mature stage in the present. This study can provide available maturity data for the next petroleum exploration work.

Source Rock Characterization Method for Petroleum Exploration

1977 ◽  
Author(s):  
J. Espitalie ◽  
M. Madec ◽  
B. Tissot ◽  
J.J. Mennig ◽  
P. Leplat
Keyword(s):  
Source Rock ◽  
Petroleum Exploration ◽  
Rock Characterization
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