Stratigraphic Trap Potential in the Lower Cretaceous Ratawi Interval, Partitioned Zone PZ, Saudi Arabia and Kuwait

2021 ◽  
Author(s):  
Ibrahim Hakam ◽  
Niall Toomey ◽  
Sujoy Ghose ◽  
Joe Ponthier ◽  
Jeremy Zimmerman
Keyword(s):  
Lower Cretaceous ◽  
Depositional Environment ◽  
High Energy ◽  
Seismic Inversion ◽  
Seismic Facies ◽  
Reservoir Quality ◽  
The North ◽  
Reservoir Development ◽  
Calcite Cement ◽  
Effective Seal

Abstract The Lower Cretaceous Ratawi Oolite Formation is among the most prolific reservoirs in the PZ, having produced a significant amount of oil since the 1950's. The Ratawi is interpreted as a low angle carbonate ramp, with high-energy grainstone facies developing on structural highs. Production is focused on these structural highs, with very few well penetrations off structure. Recent work has identified potential Ratawi stratigraphic traps in prograding clinoforms along the flanks of the North Fuwaris structural high. Core data from Ratawi wells illustrate the interplay of depositional environment and diagenesis on reservoir quality. Gross depositional environment (GDE) maps created from the integration of seismic facies and core observations indicate the stratigraphic trap lies in the ramp slope. Reservoir quality variability of the ramp slope across the PZ is explained by the diagenetic history of the Ratawi. Early equant calcite cement develops from substantial meteoric runoff and lowers porosity, while later dissolution enhances reservoir quality. The area of interest is isolated from potential meteoric inputs; we do not expect equant calcite cement or the associated reduction in reservoir quality. Seismic interpretation was performed on recently acquired PZ 3D data to map the Ratawi section. Clinoforms (inclined geometry) were mapped along the western flank of the North Fuwaris high. These facies appear to have developed as a result of progradation to the NW and are indicative of good reservoir development. Leads were generated using the depth structure and GDE maps, supported by amplitude extraction and seismic inversion volumes. Amplitudes extracted from the clinoform shows that the strongest anomaly is along the structurally highest part of the horizon and the anomaly weakens downdip. High amplitudes could be a proxy for reservoir (porosity), and sharp turn-off in amplitude might indicate that lateral and updip facies changes to non-reservoir which is needed for an effective seal. Recent seismic inversion performed on the Ratawi interval shows a good match between the Acoustic Impedance (AI) from logs and the computed AI from the seismic. The Ratawi Oolite appears as a low impedance interval between overlying Ratawi Limestone and underlying Makhul. Porosity estimated from AI volumes appear to support possible Ratawi reservoir development along the flanks of North Fuwaris and Wafra highs.

scholarly journals Sequence Stratigraphic Modeling of the Lower Thamama Group, East Onshore Abu Dhabi, United Arab Emirates

GeoArabia ◽  
1997 ◽  
Vol 2 (2) ◽  
pp. 179-202 ◽  
Author(s):  
Sabah K. Aziz ◽  
Mohamed M. Abd El-Sattar
Keyword(s):  
United Arab Emirates ◽  
Seismic Data ◽  
Depositional Environment ◽  
High Energy ◽  
Source Rocks ◽  
Abu Dhabi ◽  
Sequence Stratigraphic ◽  
Reservoir Development ◽  
Energy Environment ◽  
Exploration Activity

ABSTRACT The Lower Cretaceous (Berriasian to Valanginian) Habshan Formation (Lower Thamama Group) of Abu Dhabi was deposited on a broad carbonate shelf. In east onshore Abu Dhabi, the Habshan Formation consists mainly of limestone and dolomite reaching a thickness of more than 1,100 feet. The depositional environment ranged from shallow-water peritidal to deeper shelf basin. The integration of seismic-stratigraphic, biostratigraphic, lithostratigraphic and electric log data reveals three sequences (I to III) and three shelf edges within the Habshan Formation in east onshore Abu Dhabi. These high energy shelfal sediments prograde toward the basin to the east and northeast with their shelf edges trending north-northwest to south-southeast. The seismic data indicates that the basin was filled in the east during the Hauterivian, after the deposition of Sequence IV (equivalent to the Zakum formation). Good reservoir development is found in the carbonates deposited in the high energy environment along the shelf edge of the Habshan sequence, particularly within the oblique and sigmoidal clinoforms, whereas potential source rocks are expected to be developed basinward. This combination renders the Habshan and Zakum sequences an attractive exploration target, both as structural and stratigraphic traps. Recent exploration activity in the area established the presence of hydrocarbons within the Habshan Sequence III in east onshore Abu Dhabi.

Fatehgarh lacustrine turbidite potential, Barmer Basin, India

2019 ◽  
Vol 38 (4) ◽  
pp. 280-285
Author(s):  
Priyabrata Chatterjee ◽  
Utpalendu Kuila ◽  
B. N. S. Naidu ◽  
Hriday Jyoti Bora ◽  
Anil Malkani ◽  
...  
Keyword(s):  
Oil And Gas ◽  
Integrated Approach ◽  
Seismic Inversion ◽  
Seismic Facies ◽  
Reservoir Quality ◽  
High Quality ◽  
Passive Margins ◽  
Seismic Waveform ◽  
Barmer Basin ◽  
Environment Maps

Global discovered resources of oil and gas in giant stratigraphic and structural-stratigraphic combination traps have increased by nearly 50% in the last 17 years. Among the biggest contributors are the large discoveries in deepwater turbidite systems in passive margins and rift basins. The current study area is located in the Barmer Basin in northwestern India. Barmer Basin is a prolific petroliferous basin with major oil discoveries in structural plays including Mangala, Bhagyam, and Aishwariya fields. The principal reservoirs in the structural highs are high-quality fluvial sandstones of the Paleocene Fatehgarh Formation. Lacustrine turbidite plays have been discovered in the overlying Paleocene Barmer Hill Formation, albeit with moderate to poor reservoir quality. The potential exists, however, for finding off-structure lacustrine deepwater turbidite plays in the Paleocene Fatehgarh with reservoir quality comparable to the high-quality fluvial facies encountered updip in the structural plays. An integrated approach was adopted to identify stratigraphic entrapments across the basin to chase high-quality Fatehgarh reservoirs. Gross depositional environment maps integrating new geoscientific data were created, followed by well-calibrated seismic geomorphology and seismic facies interpretations to identify the distal lacustrine deepwater turbidite system fed by the updip fluvial Fatehgarh systems. Worldwide, the critical risk elements associated with such plays are reservoir presence, quality, and lateral seal. Geophysical tools like unsupervised seismic waveform classification, spectral decomposition, and seismic inversion were applied to the available seismic data, and the results were integrated with the regional geology and well facies information to derisk the critical risk segments.

scholarly journals Depositional environment of the Lower Cretaceous (Upper Albian) Winton Formation at Isisford, Central-West Queensland, Australia, inferred from sandstone concretions

2017 ◽  
Author(s):  
Caitlin Syme ◽  
Kevin Welsh ◽  
Eric Roberts ◽  
Steven Salisbury
Keyword(s):  
Lower Cretaceous ◽  
Depositional Environment ◽  
Soft Tissues ◽  
Ex Situ ◽  
Personal Observation ◽  
Pore Waters ◽  
Fossil Bone ◽  
Plant Fossils ◽  
Calcite Cement ◽  
Fossil Vertebrate

Numerous vertebrate and plant fossils have been found in ex-situ sandstone concretions near Isisford in central-west Queensland since the mid-1990s. These concretions are found in the Lower Cretaceous portion (upper Albian, 100.5–102.2 Ma) of the Winton Formation. The lower most Winton Formation is thought to have formed in a fluvial channel or flood-basin setting proximal to the Eromanga Sea, but due to the scarcity of good exposures, the local depositional environment at Isisford has not been ascertained. Minimal compression of vertebrate and plant fossils, a lack of grain suturing, predominantly cement-supported fabric, and fractures running through calcite cement, as well as fossil bone and framework grains, indicates that concretions formed during early diagenesis (pre-compactional or syndepositional). Calcite stable-isotope δ18OVPDB values range from –12.25 to –4‰, indicating mixed marine and meteoric pore waters, and δ13CVPDB values range from –5.3 to 4.1‰, indicative of both sulfate reduction and methanogenesis of organic material (including decaying vertebrate soft tissues) in the burial environment. The mixed marine and freshwater signature suggests a marginal marine setting, possibly deltaic or estuarine, connected to the regressive epicontinental Eromanga Seaway at around 102–100 Ma. This is not inconsistent with the lithology from nearby cores, coupled with Isisford fossil-vertebrate ecology (personal observation). Our research demonstrates the utility of investigating ex-situ concretions to refine paleoenvironments at localities where little or no outcrop is available and traditionalfacies analysis is impractical.

GEOLOGICAL CONTROLS ON RESERVOIR QUALITY OF THE NORTHERN PERTH BASIN

1987 ◽  
Vol 27 (1) ◽  
pp. 318 ◽  
Author(s):  
S.L. Bergmark ◽  
P.R Evans
Keyword(s):  
High Energy ◽  
Reservoir Quality ◽  
Gas Field ◽  
Reservoir Rocks ◽  
The North ◽  
Fan Delta ◽  
The Common ◽  
Primary Porosity ◽  
And Control

The major onshore Dongara gas field and a number of adjacent minor gas and oil pools are reservoired in basal Triassic sandstones that are sealed by the overlying Kockatea Shale. Reservoir quality is found to be controlled primarily by the local provenance of the sandstones, by diagenesis and the regional palaeotopography. Sandstones east of Dongara are reworked products of a Late Permian fan delta (Wagina Sandstone) that extended westwards from the basin's eastern, fault controlled margin. Localised high energy streams drained the palaeoslope, depositing thin wedges of mainly fluvial sediments upon and around the flanks of the Permian fan delta during a regional rise in sea level in the Early Triassic. Sandstones to the north of Dongara are localised, low energy offshore bars and strandline deposits derived from Precambrian of the Northampton Block. Diagenetic alterations of the Triassic sandstones, also controlled by the sandstones' provenance, have substantially reduced primary porosity and control permeability. The common presence of the authigenic clay mineral, dickite, is taken as evidence that a fluvial environment of deposition controlled formation of the reservoir rocks.

Lithostratigraphy, facies, mineralogy and diagenesis of the retrograding, syntectonic Neogene Barzaman Formation (Al-Khod, Sultanate of Oman)

2020 ◽  
Author(s):  
Frank Mattern ◽  
Shaima Al-Amri ◽  
Andreas Scharf
Keyword(s):  
Depositional Environment ◽  
High Energy ◽  
Silica Content ◽  
Slope Instability ◽  
Coarse Grained ◽  
Tectonic Activity ◽  
Shallow Marine ◽  
Ephemeral Ponds ◽  
Terrestrial Environments ◽  
Calcite Cement

<p>The Barzaman Formation is 150-200 m thick and subdivided into five lithostratigraphic/facies intervals recording syndepositional thrusting and changes from shallow marine to terrestrial environments and from arid/semiarid to more humid conditions.</p><p>(1) The basal lower conglomerate and sandstone unit is >36 m thick, marked by beige and gray/greenish colors, thick-bedded pebbly, calciclastic litharenites which may display parallel lamination and thick-bedded matrix-supported pebble to cobble conglomerates with subrounded clasts of chert, basalt, gabbro, quartzite and carbonates. Pores may be lined by isopachous, microcrystalline calcite cement. The depositional environment is shallow marine with one coarse-grained fill of a high-energy tidal inlet.</p><p>(2) The light-colored carbonate facies unit is 1-15 m thick, consisting of thick-bedded coral limestone, a very thick limestone coral and algae debrite and some minor beds of conglomerate and sandstone. The corals may be partly silicified by brown-stained silica. This unit was deposited in a warm, shallow marine, nearshore environment with clear water which may indicate an arid climate.</p><p>(3) The varicolored thick sandstone and conglomerate facies unit is 14-28.5 m thick. These clastic deposits are similar to those of unit 1, but more colorful, slightly coarser grained (presence of boulders) and include also thin and medium beds. The sandstones may exhibit cross-bedding. The depositional environment is shallow marine as indicated by coral debris.</p><p>(4) The claystone and conglomerate facies unit is 19 m thick. The clastic sediments are similar to those of unit 1, but pebbly sandstones are comparatively rare, and claystone beds are present, including a 20-cm-thick cellular claystone (palygorskite, vermiculite with some calcite) as well as light gray, medium-bedded claystone beds, consisting mainly of palygorskite with some saponite and/or clinochlore, associated with minute, euhedral dolomite or ankerite crystals. All claystone beds are evaporitic, lacustrine deposits of ephemeral ponds and pools on wadi floors whereas the coarser beds represent wadi conglomerates. Some beds are imbricated slide units. The paleoclimate was hot, semiarid or arid.</p><p>(5) The dolomitic conglomerate facies unit may measure >61 m in thickness. The respective pebble conglomerates consist of clasts that seem to “float” in cement. The cements of the basal >10 m are brown-stained silica and some white dolomite. The silica content gradually decreases upward. The upper part is dominated by white dolomite and some calcite. The dolomite cement may have formed under phreatic conditions (groundwater) during the Late Miocene to Pliocene when the arid/semiarid Miocene climate became more humid.    </p><p>Close to the base of unit 4, the upper part of an east-dipping syndepositional thrust is exposed (Mattern et al., 2018). Faulting approximately coincides with the change from marine to terrestrial conditions. In addition, the syndepostional tectonic activity may explain aspects of slope instability: debrite in unit 2, slide units in unit 4.</p><p> </p><p>References</p><p>Mattern, F., Scharf, A., Al-Amri, S.H.K., 2018. East-west directed Cenozoic compression in the Muscat area (NE Oman): timing and causes. Gulf Seismic Forum, 19-22 March 2018, Muscat, Oman, Book of Abstracts, p. 4-7.</p>

scholarly journals Geology of the Lower Cretaceous in the Falkebjerg area, Wollaston Forland, northern East Greenland

2020 ◽  
Vol 68 ◽  
pp. 155-169
Author(s):  
Stefan Piasecki ◽  
Jørgen A. Bojesen-Koefoed ◽  
Peter Alsen
Keyword(s):  
Lower Cretaceous ◽  
Depositional Environment ◽  
Depositional Environments ◽  
Petroleum Reservoir ◽  
Dinoflagellate Cysts ◽  
Marine Fauna ◽  
East Greenland ◽  
North West ◽  
The North ◽  
New Good

New data on the Lower Cretaceous Falskebugt Member (Palnatokes Bjerg Formation) and Stratumbjerg Formation in easternmost Wollaston Forland, northern East Greenland, are interpreted here. The type locality of the Falskebugt Member on the north-west corner of the Falkebjerg ridge has been revisited, and additional new good exposures were found in a riverbed just north of Falkebjerg and more in river beds on the plain further to the north, where both the Falskebugt Member and the Stratumbjerg Formation are exposed. Previously, only a limited marine fauna was reported providing a restricted middle Valanginian age of the Falskebugt Member. New fossil faunas in other parts of the Falskebugt Member suggest an early Valanginian – Hauterivian age and confirm lateral correlation with the Albrechts Bugt and Rødryggen Members of the Palnatokes Bjerg Formation. However, in places where the Falskebugt Member is exposed in contact with the lower Stratumbjerg Formation, dinoflagellate cysts from these units indicate Barremian and late Barremian ages, respectively. The stratigraphic range of the combined biostratigraphic data from the Falskebugt Member indicates an early Valanginian – late Barremian age. Dinoflagellate cysts from part of the assemblage in the Stratumbjerg Formation suggest a marginal marine/brackish water depositional environment. Comparable depositional environments are also recorded in upper Barremian sediments on Store Koldewey and in the Ladegårdsåen Formation on Peary Land much farther to the north in Greenland. The dark mudstones of the Stratumbjerg Formation show no potential for generation of liquid hydrocarbons, and the immature and poorly sorted sediments of the Falskebugt Member have little potential as a petroleum reservoir.

Depositional Environment Drive as Overpressure Generation: Study Case in “Gap” Field, North West Java Basin

2020 ◽  
Author(s):  
A., C. Prasetyo
Keyword(s):  
Clay Mineral ◽  
Depositional Environment ◽  
Mineral Content ◽  
Hydrocarbon Generation ◽  
Well Test ◽  
Burial History ◽  
The South ◽  
North West ◽  
The North ◽  
Geological Processes

Overpressure existence represents a geological hazard; therefore, an accurate pore pressure prediction is critical for well planning and drilling procedures, etc. Overpressure is a geological phenomenon usually generated by two mechanisms, loading (disequilibrium compaction) and unloading mechanisms (diagenesis and hydrocarbon generation) and they are all geological processes. This research was conducted based on analytical and descriptive methods integrated with well data including wireline log, laboratory test and well test data. This research was conducted based on quantitative estimate of pore pressures using the Eaton Method. The stages are determining shale intervals with GR logs, calculating vertical stress/overburden stress values, determining normal compaction trends, making cross plots of sonic logs against density logs, calculating geothermal gradients, analyzing hydrocarbon maturity, and calculating sedimentation rates with burial history. The research conducted an analysis method on the distribution of clay mineral composition to determine depositional environment and its relationship to overpressure. The wells include GAP-01, GAP-02, GAP-03, and GAP-04 which has an overpressure zone range at depth 8501-10988 ft. The pressure value within the 4 wells has a range between 4358-7451 Psi. Overpressure mechanism in the GAP field is caused by non-loading mechanism (clay mineral diagenesis and hydrocarbon maturation). Overpressure distribution is controlled by its stratigraphy. Therefore, it is possible overpressure is spread quite broadly, especially in the low morphology of the “GAP” Field. This relates to the delta depositional environment with thick shale. Based on clay minerals distribution, the northern part (GAP 02 & 03) has more clay mineral content compared to the south and this can be interpreted increasingly towards sea (low energy regime) and facies turned into pro-delta. Overpressure might be found shallower in the north than the south due to higher clay mineral content present to the north.

Sign in / Sign up

Export Citation Format

Share Document