New Finding on Oil Distribution in Jabung Block and its Implication to Pre-Talang Akar Formation (Pre-TAF) Play in the Block and South Sumatera Basin Respectively

2021 ◽  
Author(s):  
B. Syam
Keyword(s):  
Petroleum System ◽  
Reservoir Rock ◽  
Type I ◽  
The North ◽  
Oil Distribution ◽  
Kerogen Type ◽  
New Finding ◽  
Origin Of Oil ◽  
Rock Eval ◽  
3D Seismic Data

The kerogen types at the origin of oil in the Jabung block are predominantly type-II and III based on Rock Eval pyrolysis, and are interpreted to originate from the fluvio-deltaic shale & coal of the Oligocene Talang Akar Formation (TAF). However, several outlying oils have been found in the wells NB-1 & NB-4 of the North Betara Field and indicate that kerogen type-I of lacustrine origin may also be in play. This scenario is further suggested by biomarker and carbon isotope ratios. In this paper, we infer that those oils are sourced from the Eocene Pre-Talang Akar Formation (Pre-TAF) section. This opens new exploration prospectivity for the Jabung area. Our analysis of selected petroleum system elements suggests that the lacustrine oils encountered in NB-1 & NB-4 originate from Eocene Pre-TAF source rock in deeper part and migrated into the younger Oligocene TAF sandstone as a sub-surface leak, or “a subsurface oil seep”. Oil migrated by fault vertically and then spread laterally to fill traps in TAF. A widespread unconformity at top pre-TAF may have provided an excellent seal at the origin a pre-TAF confined petroleum system, prevented the lacustrine oil from entering all the fields/structures in the Jabung block, This could explain the minimal distribution of the lacustrine oil at TAF level and above in the Jabung area. The Pre-TAF is associated with the early syn-rift phase in South Sumatra Basin. It also refers as Lahat or Lemat Formation in the basin and is a widely under-explored play, evidenced by the low reserve magnitude of fewer than 100 MMBOE. The distribution of Pre-TAF as source and reservoir rock is restricted to syn-rift depocenter area. From our latest interpretation, Pre-TAF in NEB Field, observed clearly from the 3D seismic data, is potentially well developed and of good quality, although no wells have penetrated the interval to date

Depositional Environment and Petroleum System Analysis Based on Outcrop Analogue in Sukolilo Outcrop, Tuban Regency, East Java Province

2020 ◽  
Author(s):  
N., S., Irsani
Keyword(s):  
Depositional Environment ◽  
Middle Miocene ◽  
Petroleum System ◽  
Reservoir Rock ◽  
Petrographic Analysis ◽  
Carbonaceous Shale ◽  
North East ◽  
The North ◽  
Limestone Sample ◽  
Rock Eval

The North East Java Basin has become one of the most promising basins in Indonesia. Over 150 million barrels of oil have been extracted from the Rembang Zone in the North East Java Basin. The Sukolilo outcrop, located in Sukolilo, Bancar, Tuban Regency, East Java, represents all the components of an exposed Middle Miocene petroleum system. The objective of this study is to present an excellent analogue for the depositional environment and petroleum system of the Middle Miocene formation of the Rembang Zone that can be expected in similar subsurface settings and as a tool for outcrop preservation with modelling using photogrammetry. Data consists of measured section, photogrammetry data, petrographic analysis, TOC content measurement and Rock-Eval Pyrolysis. Observed formation at this outcrop includes Ngrayong, Bulu, and Wonocolo Formation. The facies distributed in this outcrop consist of claystone-carbonaceous shale bedded, cross-bedded quartz sandstone, foraminiferal limestone and calcareous siltstone intercalated calcareous sandstone. Based on depositional environment analysis, the depositional environment changes from Lagoon – Tidal Flat – Shallow Marine – Shelf. The result of petrographic analysis shows that quartz sandstone porosity from the Ngrayong Formation can be identified as reservoir rock. Seal rock potential is shown by carbonate minerals diagenesis of the foraminiferal limestone sample. Source rock potential which is identified using TOC content and Rock-Eval Pyrolysis, reveals that the sample tends to be gas prone (kerogen type III) and has low thermal maturity (immature). Ductile deformation (conical anticline) and brittle deformation (normal fault) is predicted to be the migration path for this petroleum system.

scholarly journals Chronostratigraphy, palynofacies, source-rock potential, and organic thermal maturity of Jurassic rocks from Qatar

GeoArabia ◽  
2002 ◽  
Vol 7 (4) ◽  
pp. 675-696
Author(s):  
Mohamed I. A. Ibrahim ◽  
Hamad Al-Saad ◽  
Suzan E. Kholeif
Keyword(s):  
Organic Matter ◽  
Source Rock ◽  
Reservoir Rock ◽  
Inert Material ◽  
Type I ◽  
Carbonate Sediments ◽  
Type Ii ◽  
Type Iii ◽  
Kerogen Type ◽  
Marine Algal

ABSTRACT Strontium isotope, palynological, and total organic carbon (TOC) analyses were made on core samples from the Izhara, Araej, and Hanifa formations of three wells in onshore Qatar. Eleven samples were analyzed for their 87Sr/86Sr ratios. The results gave a chronostratigraphic range of Early Jurassic (Hettangian) to Late Jurassic (Oxfordian), with an overall age range of 202.4 Ma to 157.8 Ma. Maximum flooding surfaces MFS J10 to MFS J50 occur in the Izhara, Araej, and Hanifa formations. The organic matter in the carbonate sediments of the Izhara, Araej, and Hanifa formations was almost exclusively of marine algal origin dominated by marine microplankton. Organic matter obtained from the Izhara Formation was mature to over-mature kerogen type-III to IV, gas-prone to inert material (mean TOC 0.31%). In the Araej Formation, mature oil-prone and gas-prone kerogen type-II and type-III organic matter occurred in both the lower and upper Araej members (TOC 0.13-0.69%). The stylolitic limestone of the Uwainat member of the Araej Formation has poor potential as a source rock for petroleum (TOC 0.03-0.13%), but is considered to be the main reservoir rock of the Middle Jurassic in Qatar. Mature, highly oil-prone organic matter (type-I and type-II kerogen) was present in black limestone of the Hanifa Formation (mean TOC 0.60%; maximum 0.93%). The limestone is considered to be the most likely petroleum source rock for the underlying and overlying limestone reservoirs of the Uwainat member of the Araej Formation (Bathonian) and the Arab-D member of the Arab Formation (Kimmeridgian) units, respectively.

scholarly journals Application of X-ray Diffraction (XRD) and Rock–Eval Analysis for the Evaluation of Middle Eastern Petroleum Source Rock

Energies ◽  
2021 ◽  
Vol 14 (20) ◽  
pp. 6672
Author(s):  
Golam Muktadir ◽  
Moh’d Amro ◽  
Nicolai Kummer ◽  
Carsten Freese ◽  
Khizar Abid
Keyword(s):  
Specific Surface ◽  
Surface Area ◽  
Source Rock ◽  
Specific Surface Area ◽  
Oxygen Index ◽  
Hydrogen Index ◽  
Type I ◽  
Type Ii ◽  
Kerogen Type ◽  
Rock Eval

In this study, collected samples of nine different wells from the Middle East are used for various geochemical analyses to determine the hydrocarbon generation potential. The determination is carried out following the grain density, specific surface area, XRD, and Rock–Eval pyrolysis analyses. Four different types of kerogen are plotted based on the Rock–Eval analysis result. Kerogen type I usually has high hydrogen index (e.g., HI > 700) and low oxygen index, which is considered oil-bearing. Kerogen Type II has hydrogen index between type I and type II and oxygen index higher than type I (e.g., 350 < HI < 700) and is also considered to have oil-bearing potential. Kerogen type III has a lower hydrogen index (e.g., HI < 350) and is considered to have a primarily gas-generating potential with terrigenous organic matter origination. Kerogen type IV has a very low hydrogen index and higher oxygen index (compared with other types of kerogen), which is considered the inert organic matter. The kerogen quality of the analyzed samples can be considered as very good to fair; the TOC content ranges from 1.64 to 8.37 wt% with most of them containing between 2 and 4 wt%. The grain density of these examined samples is in the range of 2.3–2.63 g/cc. The TOC and density of the samples have an inversely proportional relationship whereas the TOC and the specific surface area (BET) has a positive correlation. The specific surface area (BET) of the examined samples is in the range of 1.97 m2/g–9.94 m2/g. The examined samples are dominated by clay, primarily kaolinite and muscovite. Additionally, few samples have a higher proportion of quartz and calcite. The examined samples from the Middle East contain kerogen type III and IV. Only two samples (JF2-760 and SQ1-1340) contain type I and type II kerogen. Considering Tmax and Hydrogen Index (HI), all of the samples are considered immature to early mature. Rock–Eval (S2) and TOC plotting indicate that most of the samples have very poor source rock potential only with an exception of one (JF2-760), which has a fair-to-good source rock potential.

scholarly journals Geochemical Considerations from the Carboniferous Unconventional Petroleum System of SW Iberia

Minerals ◽  
2021 ◽  
Vol 11 (8) ◽  
pp. 811
Author(s):  
Gabriel A. Barberes ◽  
Rui Pena dos Reis ◽  
Nuno L. Pimentel ◽  
André L. D. Spigolon ◽  
Paulo E. Fonseca ◽  
...  
Keyword(s):  
Random Distribution ◽  
Thermal Evolution ◽  
Organic Geochemistry ◽  
Black Shales ◽  
Petroleum System ◽  
Point Of View ◽  
Gas Reservoir ◽  
Thermal Maturation ◽  
Petrographic Analyses ◽  
Rock Eval

The Baixo Alentejo Flysch Group (BAFG) is an important stratigraphic unit that covers over half of the South Portuguese Zone (SPZ) depositional area, and it is composed by three main tectono-stratigraphic units: the Mértola, Mira, and Brejeira formations. All of these formations contain significant thicknesses of black shales and have several wide areas with 0.81 wt.%, 0.91 wt.%, and 0.72 wt.% average total organic carbon (TOC) (respectively) and thermal maturation values within gas zones (overmature). This paper is considering new data from classical methods of organic geochemistry characterization, such as TOC, Rock–Eval pyrolysis, and organic petrography, to evaluate the unconventional petroleum system from the SPZ. A total of 53 samples were collected. From the stratigraphical point of view, TOC values seem to have a random distribution. The Rock–Eval parameters point out high thermal maturation compatible with gas window (overmature zone). The samples are dominated by gas-prone extremely hydrogen-depleted type III/IV kerogen, which no longer has the potential to generate and expel hydrocarbons. The petrographic analyses positioned the thermal evolution of these samples into the end of catagenesis to metagenesis (wet to dry gas zone), with values predominantly higher than 2 %Ro (dry gas zone). The presence of thermogenic hydrocarbon fluids characterized by previous papers indicate that the BAFG from SPZ represents a senile unconventional petroleum system, working nowadays basically as a gas reservoir.

scholarly journals Geological evolution of the Chalk Group in the northern Dutch North Sea: inversion, sedimentation and redeposition

2018 ◽  
Vol 156 (07) ◽  
pp. 1265-1284
Author(s):  
EVA VAN DER VOET ◽  
LEONORA HEIJNEN ◽  
JOHN J. G. REIJMER
Keyword(s):  
North Sea ◽  
Late Cretaceous ◽  
Seismic Survey ◽  
Structural Elements ◽  
The North ◽  
Show Evidence ◽  
New Finding ◽  
The North Sea ◽  
Thickness Variations ◽  
Well Data

AbstractIn contrast to the Norwegian and Danish sectors, where significant hydrocarbon reserves were found in chalk reservoirs, limited studies exist analysing the chalk evolution in the Dutch part of the North Sea. To provide a better understanding of this evolution, a tectono-sedimentary study of the Late Cretaceous to Early Palaeogene Chalk Group in the northern Dutch North Sea was performed, facilitated by a relatively new 3D seismic survey. Integrating seismic and biostratigraphic well data, seven chronostratigraphic units were mapped, allowing a reconstruction of intra-chalk geological events.The southwestward thickening of the Turonian sequence is interpreted to result from tilting, and the absence of Coniacian and Santonian sediments in the western part of the study area is probably the result of non-deposition. Seismic truncations show evidence of a widespread inversion phase, the timing of which differs between the structural elements. It started at the end of the Campanian followed by a second pulse during the Maastrichtian, a new finding not reported before. After subsidence during the Maastrichtian and Danian, renewed inversion and erosion occurred at the end of the Danian. Halokinesis processes resulted in thickness variations of chalk units of different ages.In summary, variations in sedimentation patterns in the northern Dutch North Sea relate to the Sub-Hercynian inversion phase during the Campanian and Maastrichtian, the Laramide inversion phase at the end of the Danian, and halokinesis processes. Additionally, the Late Cretaceous sea floor was characterized by erosion through contour bottom currents at different scales and resedimentation by slope failures.

scholarly journals Geostatistical Model for the Arab-D Reservoir, North ’Ain Dar Pilot, Ghawar Field, Saudi Arabia: An Improved Reservoir Simulation Model

GeoArabia ◽  
1996 ◽  
Vol 1 (2) ◽  
pp. 267-284
Author(s):  
John L. Douglas ◽  
Keyword(s):  
Saudi Arabia ◽  
Fluid Flow ◽  
Reservoir Rock ◽  
Well Test ◽  
Geostatistical Model ◽  
Deterministic Models ◽  
Modeling Approach ◽  
The North ◽  
Porosity And Permeability ◽  
Ghawar Field

ABSTRACT The North ‘Ain Dar 3-D geocellular model consists of geostatistical models for electrofacies, porosity and permeability for a portion of the Jurassic Arab-D reservoir of Ghawar field, Saudi Arabia. The reservoir consists of a series of shallow water carbonate shelf sediments and is subdivided into 10 time-stratigraphic slices on the basis of core descriptions and gamma/porosity log correlations. The North ‘Ain Dar model includes an electrofacies model and electrofacies-dependent porosity and permeability models. Sequential Indicator Simulations were used to create the electrofacies and porosity models. Cloud Transform Simulations were used to generate permeability models. Advantages of the geostatistical modeling approach used here include: (1) porosity and permeability models are constrained by the electrofacies model, i.e. by the distribution of reservoir rock types; (2) patterns of spatial correlation and variability present in well log and core data are built into the models; (3) data extremes are preserved and are incorporated into the model. These are critical when it comes to determining fluid flow patterns in the reservoir. Comparison of model Kh with production data Kh indicates that the stratigraphic boundaries used in the model generally coincide with shifts in fluid flow as indicated by flowmeter data, and therefore represent reasonable flow unit boundaries. Further, model permeability and production estimated permeability are correlated on a Kh basis, in terms of vertical patterns of distribution and cumulative Kh values at well locations. This agreement between model and well test Kh improves on previous, deterministic models of the Arab-D reservoir and indicates that the modeling approach used in North ‘Ain Dar should be applicable to other portions of the Ghawar reservoir.

scholarly journals A Mesoproterozoic iron formation

2018 ◽  
Vol 115 (17) ◽  
pp. E3895-E3904 ◽  
Author(s):  
Donald E. Canfield ◽  
Shuichang Zhang ◽  
Huajian Wang ◽  
Xiaomei Wang ◽  
Wenzhi Zhao ◽  
...  
Keyword(s):  
Organic Matter ◽  
Time Window ◽  
Iron Formation ◽  
The North ◽  
Fe Oxidation ◽  
Organic Biomarkers ◽  
Rock Eval ◽  
Fe Reduction ◽  
Rule Out ◽  
Xiamaling Formation

We describe a 1,400 million-year old (Ma) iron formation (IF) from the Xiamaling Formation of the North China Craton. We estimate this IF to have contained at least 520 gigatons of authigenic Fe, comparable in size to many IFs of the Paleoproterozoic Era (2,500–1,600 Ma). Therefore, substantial IFs formed in the time window between 1,800 and 800 Ma, where they are generally believed to have been absent. The Xiamaling IF is of exceptionally low thermal maturity, allowing the preservation of organic biomarkers and an unprecedented view of iron-cycle dynamics during IF emplacement. We identify tetramethyl aryl isoprenoid (TMAI) biomarkers linked to anoxygenic photosynthetic bacteria and thus phototrophic Fe oxidation. Although we cannot rule out other pathways of Fe oxidation, iron and organic matter likely deposited to the sediment in a ratio similar to that expected for anoxygenic photosynthesis. Fe reduction was likely a dominant and efficient pathway of organic matter mineralization, as indicated by organic matter maturation by Rock Eval pyrolysis combined with carbon isotope analyses: Indeed, Fe reduction was seemingly as efficient as oxic respiration. Overall, this Mesoproterozoic-aged IF shows many similarities to Archean-aged (>2,500 Ma) banded IFs (BIFs), but with an exceptional state of preservation, allowing an unprecedented exploration of Fe-cycle dynamics in IF deposition.

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