Shale Intercalations Research Articles

Depositional Environment of Nampol Formation and Its Implications as Potential Source Rocks in the Sumbermanjing Area, South Malang

The decline in oil and gas production inevitably forces explorationists to be more creative in finding new potential reserves. Nampol Formation is expected to have the potential to become hydrocarbon source rocks due to their organic matter content. However, the depositional environment of Nampol Formation has not been thoroughly researched. The focus of this research is to reveal the depositional environment of Nampol Formation that may lead to a suitable condition for the deposition of potential source rocks layers. Detailed geological mapping in several selected traverses and micropaleontological analysis was carried out to determine lithological characteristics and depositional environment of Nampol Formation. The microfacies approach was also used to determine the carbonate facies zone of this unit. Source rock samples taken from outcrops on the surface then were analysed to evaluate organic matter content, type of kerogen thermal maturity, and its potential to produce hydrocarbons. The Nampol clastic limestone unit in the study area is composed of clastic limestone with intercalation of black shale, claystone, siltstone, sandstone and calcareous claystone. The microfacies approach shows that the wackestone and mudstone belong to the SMF 15-M (Ooid wackestone) and SMF 23 (Non-fossiliferous mudstone) which can be interpreted belong to Facies Zone (FZ) 8 in the Flügel carbonate facies model (2004). This zone is located in the Restricted interior platform or platform environment with closed water circulation which is situated behind the barrier reef (back reef). Based on the results of geochemical analysis, source rock samples from Nampol Formation can be considered as a gas prone source rock, with type III kerogen, total organic content ranging from 3.48 – 26.18 wt%, po-sess the potential to produce

Biostratigraphy, microfacies and sequence stratigraphic analysis of the Chorgali Formation, Central Salt Range, northern Pakistan

In present study three sections of early Eocene Chorgali Formation were measured from Pail, Wanhar and Sar Kalan area, Central Salt Range, Punjab, Pakistan. At these localities the Chorgali Formation is about 12m, 8.8m and 15.1m thick, respectively. A total number of 53 samples were collected, 18 from Pail section, 18 from Wanhar section and 17 from Sar Kalan section. Eocene Chorgali Formation in this area is consisted of grey to pale grey limestone, greenish grey shale intercalations and argillaceous limestone. At Pail section nine various microfacies were recorded i.e., Mudstone microfacies (CGP1), Bioclastic mudstone microfacies (CGP2), Nummulites-Lockhartia wackestone microfacies (CGP3), Nummulitidae wackestone microfacies (CGP4), Bioclastic wackestone microfacies (CGP5), Alveolina-Nummulites wackestone microfacies (CGP6), Alveolina wackestone microfacies (CGP7), Nummulites-Alveolina wackestone microfacies (CGP8) and Intraclastic-peloidal packstone microfacies (CGP9).At Wanhar section five facies were recorded i.e., Rotaliidae wackestone microfacies (CGW1), Nummulitidae Wackestone microfacies (CGW2), Nummulites- Lockhartia wackestone microfacies (CGW3), Nummulites-Assilina wackestone microfacies (CGW4), Intraclastic-peloidal packstone microfacies (CGW5).At Sar Kalan section total four facies were recorded i.e., Bioclastic wackestone microfacies (CGSK1), Nummulites-Assilina wackestone microfacies (CGSK2), Nummulitidae wackestone microfacies (CGSK3), Intraclastic-peloidal packstone microfacies (CGSK4).The assemblage of larger foraminifera were recorded to describe the biota of the formation and to interpret the paleo-environments with implications of sequence stratigraphy. Field observations and microfacies analysis suggest that the deposition of Chorgali Formation at these localities probably took place in inner shelf conditions. Presence of shallow water benthic larger foraminifer's further support lagoon to bay environment of the genesis of the formation. The formation might have been deposited because of falling stage system tract (FSST), showing a progradational pattern of deposition. The basin ward shift of deposition indicates the regressive sequence.

Poznámky k faciálnímu vývoji letenského souvrství (svrchní ordovik, sandbian) v severní části pražské pánve

About 100–150 m thick intercalation of dark micaceous siltstone to black clayey shale can be distinguished in the middle part of the Letná Formation (Upper Ordovician, Lower Sandbian) at several localities in the NW and NE parts of the Prague Basin. Sandstone and greywacke, dominant elsewhere in this formation, form only a subordinate part of the sequence. In the NW belt of the Letná Formation, N of the Prague Fault (see Fig. 1C), this thick intercalation has been previously known from Bulovka – Bílá Skála Rock and from Rudolfova Štola Gallery (Röhlich 1956, 1960; Mikuláš 1994). A comparable, slightly thinner, and locally discontinuous intercalation of dark siltstone and black clayey shale was described also in the middle belt of the Letná Formation, S. of the Prague Fault (see Fig. 1C) by Röhlich (1956, 1960); such lithology is known from the Praha – Žižkov, Kyje and Malešice areas. An equivalent of this interlayer was documented by Budil (1996) in the middle part of the Letná Formation from the Černý Most area. No such interlayer of dark, fine-grained sediments has been reported from the southern belt of the Letná Formation (Fig. 1C), most probably because of its much poorer exploration. New borehole documentation at Praha – Střešovice extends our knowledge on the above – discussed dark siltstone and claystone intercalation in the NW belt of the Letná Formation. In two boreholes (HJ 11 and HJ 16), more than 60 m thick sequence of dark, fine-grained sediments has been documented in the middle part of the Letná Formation. The presence of these sediments was confirmed also by the study of archive data – previous geotechnical documentation of this area. The archive data documented the presence of a second, thinner and rather lens- like body of dark, fine-grained sediments which can be traced in the lower third of the Letná Formation in the Střešovice area. It is suggested that the sedimentation of relatively thick sequences of dark siltstones and shales reflects short-time periods of decrease in the input of clastic material. Alternatively, it could correspond to a partial, synsedimentary tectonic-related deepening of respective parts of the sedimentary basin. Locally bioturbated black siltstone and shale sequence is barren of benthos and contains only rare remains of indeterminable linguliformean brachiopods. It is supposed that such association corresponds to the Paterula Com- munity of Havlíček (1982), so far only poorly documented from the Letná Formation (Van Roy et al. 2021)

Petrophysical evaluation of sandstone gas reservoir using integrated well logs and core data for the Lower Cretaceous Kharita formation, Western Desert, Egypt

This study aims to evaluate Kharita gas reservoir to enhance the production. The increase in water-cut ratio reduces the left hydrocarbons’ amount behind pipe. Accurate determination of pore throats, pores connectivity and fluid distribution are central elements in improved reservoir description. The integration of core and logging data responses is often used to draw inferences about lithology, depositional sequences, facies, and fluid content. These inferences are based on petrophysical models utilizing correlations among tools’ responses as well as rocks and fluids properties. Upper Kharita Formation produces gas and condensate from the clastic sandstone in Badr-3 field, western desert of Egypt. It consists mainly of sandstone with shale intercalations. It is subdivided into three sub-units Kharita A, Kharita B and Kharita C that are in pressure communication. Hence, a new further investigation and review for the previously calculated GIIP (gas initially in place) was initiated. The results of this study yielded that the main uncertainty in the volumetric calculations was the petrophysical evaluation; subsequently, a new unconventional petrophysical evaluation approach was performed. The sands thickness in Upper Kharita Formation varies between more than 9 up and more than 61 m with average porosity values range between 0.08 and 0.17 PU while the average permeability values range between 1.89 and 696.66 mD. The average hydrocarbon saturation values range between 46 and 97%. The sands thickness in Upper Kharita Formation varies between more than 9 up and more than 61 m with average porosity values range between 0.08 and 0.17 PU while the average permeability values range between 1.89 and 696.66 mD. The average hydrocarbon saturation values range between 46 and 97%. Reservoir shale cutoff of 55% by using cross-plot between shale volume and porosity (Toby Darling concept) was utilized to discriminate the reservoir from non-reservoir sections. The porosity model was used to calculate reservoir porosity, using the density log. The Archie and saturation/height function models were used to calculate the water saturation and used to calibrate the water saturation in the transition zone. The porosity–permeability (POR-PERM) transform equation was used to estimate the reservoir connectivity (absolute permeability) for the four petrophysical facies (High Quality Reservoir, Moderate Quality Reservoir, Low Quality Reservoir and Highly Shale Reservoir). Core data have shown variations in reservoir quality parameters (porosity and permeability) from one well to the other. Integration of all the reservoir pressures indicated that there are different fluid types (oil, gas and water) in the Upper Kharita Formation level. The saturation/height function model was used to calibrate the saturation in the transition zone. The integration of geological core and geophysical log data helped to conduct a comprehensive petrophysical assessment of Upper Kharita Formation for a better estimation of the reservoir and to achieve a better understanding of the water encroachment in the Upper Kharita reservoir. The big challenge is the determination of the most correct model for calculating porosity, permeability and water saturation in this reservoir of different quality sand. The new petrophysical evaluation resulted in doubling the volumes in Upper Kharita reservoir and so a perforation campaign was performed to confirm the new volumetric calculations, which showed a good match with the model results. Hence, a new well was drilled targeting the low quality sand and found them with high pressure almost near virgin pressure.

Petrophysical and geomechanical characterization of the Late Cretaceous limestone reservoirs from the Southeastern Constantine Basin, Algeria

We have characterized the petrophysical and geomechanical properties of the Late Cretaceous Turonian and Cenomanian carbonate reservoirs from the southeast Constantine Basin, northern Algeria. In general, Turonian carbonates exhibit a wide range of porosities (2%–15%) and permeabilities (0.001–10 mD), whereas the Cenomanian reservoir appears to be very tight (<6% porosity and <0.1 mD permeability). Based on their storage and hydraulic flow characteristics, these carbonates were classified into two distinct reservoir rock types (RRT): RRT-I is hosted by nano- to microporosities that displays poor reservoir qualities compared to the RRT-II, consisting of mesoporous Turonian intervals (>10% porosity and 0.5–10 mD permeability). The reservoir pore-pressure gradient is interpreted to be a little above the hydrostatic (0.51 psi/ft), whereas the minimum horizontal stress ([Formula: see text]) has a 0.72 psi/ft gradient. In situ stress analysis establishes a dominant strike-slip tectonic stress field in the basin. Shale intercalations associated with the carbonate facies are characterized by comparatively high failure pressure that can lead to wellbore failures, which may be avoided considering the recommended minimum drilling mud weight as obtained from the rock failure criterion. Extensive wellbore breakouts (C-quality) were observed in the acoustic image logs recorded in the studied reservoir intervals, inferring a mean maximum horizontal stress azimuth of 350°N. We recommend that deviated wells in the direction of the interpreted [Formula: see text] orientation (approximately east–west) using hydraulic fracturing can be useful to attain optimum wellbore stability and effective permeability enhancement. Our findings have significant implications for enhanced production within the tight carbonate reservoirs situated in a strike-slip domain.

Evolution of the gold (copper) mineralization in the porphyry stock and the related skarn zones and epithermal veins in the Astarghan area, NW Iran: Evidence from fluid inclusion, mineral chemistry and sulfur isotope analyses

The Astarghan area in northwest Iran (~50 km north of Tabriz) represents an excellent example of coexisting and associated skarn, porphyry and epithermal mineralizations of copper and gold. This contribution aims to study the geology, alteration and mineralization in these deposits, as well as the occurrence of gold and its host minerals, and present the physico-chemical characteristics of ore-forming fluids and the sulfur origin, in order to get a better understanding of development and evolution of these mineralizations. The Astarghan porphyry stock (Oligo–Miocene) intruded the upper Cretaceous flysch-type sedimentary sequence (calcareous sandstone and limestone with intercalations of siltstone, shale and marl) and brought about metamorphism and metasomatism along the contact. The Cu–Au mineralization in the Astarghan area occurred mainly in three forms: (1) skarn patches along the contact (Zone A), (2) stockwork-type and disseminated porphyry mineralization within the potassic (at Kaghdara and Boiokwari areas) and phyllic (at Sildirimdara area) alteration zones (Zone B), and (3) native gold-bearing low-sulfidation epithermal veins within the argillic alteration zone at Nowrozkala area (Zone C). The micro-thermometric studies on the porphyry-type Kaghdara potassic alteration zone showed that homogenization temperatures for liquid-rich and vapor-rich 2-phase, as well as halite-bearing multiphase inclusions range about 160–420 °C, 220–460 °C, and 320–580 °C, respectively. Salinities of the 2-phase and multiphase inclusions have ranges of 5–25 and 40–70 wt% NaCleq., respectively. However, fluid inclusions present in the epithermal veins of Nowrozkala are mainly liquid-rich 2-phase, and their homogenization temperature and salinity values lie within the ranges of 118–325 °C and 0.6–7.4 wt% NaCleq., respectively. The approximate estimated depth of the sulfide and gold mineralization in the porphyry system ranges from 1.6 to 2.5 km, and in the epithermal system is < 0.9 km. The sulfur isotopic analysis of pyrite from the porphyry and epithermal mineralizations in the potassic alteration zone at Kaghdara and argillic alteration zone at Nowrozkala indicate that the δ34S values (–0.1 to –0.3 and –0.5 to –1.1‰, respectively) are close to the range of magmatic sources. Finally, electron probe micro-analyses indicate that besides independent particles of 50–200 μm in the epithermal veins, gold is mainly hosted by tetrahedrite within the porphyry-related phyllic alteration zone, but especially stibnite within the epithermal veins; these minerals, as well as epithermal polyhedral pyrites contain native gold inclusions.

Lithofacies Analysis and Qualitative Minerology of the Sediments of #3 Well in the Greater Ughelli Depobelt, Niger Delta Basin

The sediment of #3 Well of the Greater Ughelli Depobelt are represented by sand and shale intercalation. In this study, lithofacies analysis and X-ray diffraction technique were used to characterize the sediments from the well. The lithofacies analysis was based on the physical properties of the sediments encountered from the ditch cuttings. Five lithofacies types of mainly sandstone, clayey sandstone, shaly sandstone, sandy shale and shale and 53 lithofacies zones were identified from 15 ft to 11295 ft. The result of the X-ray diffraction analysis identified that the following clay minerals – kaolinite, illite/muscovite, sepiolite, chlorite, calcite, dolomite; with kaolinite in greater percentage. The non-clay minerals include quartz, pyrite, anatase, gypsum, plagioclase, microcline, jarosite, barite and fluorite; with quartz having the highest percentage. Therefore, due to the high percentage of kaolinite in #3 well, the pore filing kaolinite may have more effect on the reservoir quality than illite/muscovite, chlorite and sepiolite. By considering the physical properties, homogenous and heterogeneous nature of the #3 Well, it would be concluded that #3 Well has some prospect for petroleum and gas exploration.

Foraminifera biostratigraphy and paleoenvironmental studies of well-x, eastern Niger delta

Ditch cutting samples from Well-X drilled in the Eastern part of the Niger delta were subjected to biostratigraphy and paleoenvironmental studies using micropaleontological analysis to identify the foraminifera present in the sections penetrated by the well.A total of 50 (fifty) foraminifera species made up of benthonic and planktic spp were recovered from the sections. The marker species identified are Globorotalia acostaensis, Globorotalia mernadii cultrate, Neogloboquadrina dutertrei, Globorotalia plesiotumida, Globorotalia obesa, Globorotalia nepenthes, Sphaeroidinella subdehiscens, Neogloboquadrina dutertrei, Globigerinoides sudquadratus.The four (4) biozones identified are N16 (Late Miocene 9.5Ma - 10.9Ma), N15-N14, N13-N12 and N12-N11 (Middle Miocene with corresponding ages 10.9Ma -11.8Ma, 11.8Ma-12.2Ma and 12.2Ma respectively).Using the encountered benthonic foraminiferal species, the paleoecology was determined; and it was revealed that the paleoenvironment of the section ranges from Inner Neritic to Outer Neritic Environment. Also, the lithological analysis revealed an intercalation of Shale, Mudstone and Sand which indicates various paleoecological episodes that led to their deposition.The age of the well was inferred from the bioevents of the marker species to be Middle Miocene to Late Miocene with the sparse occurrence of the Calcareous Benthic and the Plankonic species suggesting a shallow marine environment.  Â

Addendum to the chemostratigraphy of the uppermost Callovian–middle Oxfordian interval of the Tethyan Fatricum domain (Tatra Mts, Krížna Nappe, southern Poland)

New isotope (δ 13 C, δ 18 O of bulk carbonates) and carbonate content data from the uppermost Callovian–middle Oxfordian radiolarites of the Fatricum domain belonging to the north-western segment of the Tethys are added to previously published data. The new data supplement the Długa Valley section, the most nearly complete Bajocian–lower Tithonian section of the Krížna Nappe in the Tatra Mts. The uppermost Callovian and Lower Oxfordian bulk δ 13 C values (from 3.1 to 3.3‰) remain nearly constant with highly positive values. Therefore, the positive excursion identified in bulk carbonate δ 13 C values is interpreted as a record of the upper Callovian–middle Oxfordian global phenomenon. In this interval, a significant increase of CaCO 3 content is recorded, which accompanies facies change from ribbon radiolarites with siliceous shale partings to calcareous radiolarites with rare shale intercalations. The abrupt CaCO 3 increase may reflect a turning point in Early Oxfordian carbonate production and recovery of the marine carbonate factory.

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

Selected 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.

Application of machine learning tool to predict the porosity of clastic depositional system, Indus Basin, Pakistan

Porosity is one of the key factors of a reservoir system that is typically distributed in a spatially non-uniform and non-linear manner. Nevertheless, spatial distribution of porosity in stratigraphic traps (channel sand bodies) is challenging due to the variations in depositional environments, shale intercalation, and repetition of textural changes in the pore sizes. This paper presents a strategy of joint inversion that combines support vector machine (SVM) and particle swarm optimization (PSO) algorithms to predict the spatial distribution of porosity using well logs and seismic data. In addition, Gaussian simulation algorithms (sequential Gaussian and Gaussian indicator simulations) were used to predict lithology and porosity distribution using wireline logs and core data. Rock physics modeling was performed to bridge the gap between the elastic and petrophysical properties for seismic-inversion based reservoir characterization. The results show that the joint inversion strategy leads to the most stable prediction of AI and porosity distribution in the lower Goru heterogeneous reservoir of Sawan Gas Field, Pakistan. The calibration of the individual spatial distribution of lithology and porosity from wireline logs data using Gaussian simulation algorithms and post-stack seismic inversion using SVM and PSO; revealed favorable matching. In fact, the spatial pattern of low AI corresponds with the high porosity and sandstone lithofacies. The study results provide valuable insights for identifying the sweet spots in the heterogeneous lower Goru clastic packages of Sawan Gas Field through quantitative analysis of rock physics, petrophysics, seismic inversion, and fuzzy optimization. The proposed joint inversion strategy may be considered useful for the prediction of porosity in similar context of extremely heterogeneous stratigraphic traps in other basins of the world.

1D and 2D basin modeling, in evaluating the hydrocarbon generation-migration-accumulation potential, at coastal Fars Area, Southern Iran

One of the giant hydrocarbon generation zones in Iran has been developed in the south of the Zagros Mountain Range (i.e., South Zagros), located between the South Zagros and the Persian Gulf in a foreland basin known for high levels of exploration uncertainties (due to the presence of complex structures, multiple source layers, and migration pathways). In this basin, the Permotriassic formations provide for the main reservoir strata, while the hydrocarbon content is deemed to be derived from the “hot shales” of the Silurian-Ordovician Sarchahan Formation, serving as source rock. As the focus of the present research, the Coastal Fars region is developed along the shores of southern Iran and hosts a number of gas reservoirs that have been increasingly discovered since 1970. Developed in the Permotriassic siliciclastics and carbonates of the Faraghan, Dalan, and Kangan Formations, gas reservoirs have made the Coastal Fars a hot zone for exploration and production activities. In this research, one 2D and five 1D models of the basin (at five exploration wells) were constructed to evaluate the maturity of the main Silurian-Ordovician source rock and further investigate the hydrocarbon charge, timing, migration pathways, and accumulation sites. The models were then utilized to investigate the relationship between the presence of multiple shale layers and hydrocarbon content of the reservoir at one of the studied wells using Rock-Eval analysis. This study showed that an uplift that happened after the hydrocarbon generation has led to a dry hole in the study area. The results indicated that the Sarchahan Formation is probably the main source rock across the region, according to previous researches in this area its organic contents were dated back to the late Ordovician rather than the Silurian. The shale intercalations across the reservoirs (Kangan and Upper Dalan), especially in the Khayam Field, were found to produce more than 90% of their hydrocarbon generation potential. No non-indigenous hydrocarbon was identified across the study area, implying that the entire hydrocarbon content was generated by the identified source rocks. Laboratory analysis indicated the presence of type II and type III kerogen at a local heat flow rate of about 65 mW/m2 since the Cretaceous. In total, the Sarchahan Formation was found to reach a maximum burial depth of 6 km, making it matured to overmatured all over the study area.

Microfaunal Signals and Paleoenvironmental Reconstruction Sediments in Well Z-1, Offshore Dahomey Basin, South-Western Nigeria

Fifty ditch cutting rock samples from well Z-1, OPL 310 offshore Dahomey basin, south western Nigeria were analyzed for their microfaunal and lithofacies content for the purpose of reconstructing the environment of deposition. Standard techniques of foraminifera slide processing and analysis was followed for the recovery of foraminifera while the gamma ray log complemented the rock samples for the lithofacies analysis. The lithological analysis revealed two lithofacies units in a generally fining upward sequence. The basal sandstone unit is characteristically milky white to brownish, coarse-pebbly grained, sub-angular to round and poorly to well sort with intercalation of shale. This unit is overlain by light to dark grey, moderately hard and non-fissile shale/mudstone sequence with intercalation of sand. Accessory mineral assemblage present in the formations includes mica flakes, glauconite pellets, carbonaceous detritus and ferruginous materials. The basal sandstone unit belong to the Oshosun Formation while the upper shaly unit is typical of Afowo Formation. Microfaunal study showed good recovery of abundant and well diversified planktic and benthic foraminiferal species. Forty-two (42) planktic, sixty-five (65) benthic calcareous and one benthonic arenaceous foraminiferal species were recovered. Micropaleontologically, Paleoenvironmental deductions were based primarily on the assemblage, abundance and diversity of benthic foraminiferal species and presence or absence of planktic foraminifera. Accessory mineral presence also aided the interpretations. Integration of lithological and micropaleontological synthesis enhanced the delineation of two environmental subzones over the analyzed interval, the outer neritic and the upper bathyal depositional settings corresponding to Afowo and Oshosun Formation respectively. A lowstand prograding wedge which is a good exploration target offshore was recognized between intervals 3400 ft to 3500 ft. In conclusion, the rock succession studied, penetrated Afowo and Oshosun Formations, and were deposited in an environment ranging from outer neritic to upper bathyal settings.

Model Based Inversion of Acoustic Impedance from Seismic Trace for Lithofacies Differentiation: an Application in Xy Field Offshore Niger Delta

This study presents the result of a Model-based seismic inversion technique which was used to invert an acoustic impedance structure within a reservoir interval by intergrating well logs and 3D post stack seismic data obtained from XY field offshore Niger Delta. The purpose was to delineate lateral and vertical alternations in subsurface rock properties which is caused by difference in lithofacies within the reservoir interval. This would help to define hydrocarbon fairways better and constrain the range of hydrocarbon zones for field development. The inversion workflow used in this study includes forward modelling of reflection coefficients from a low frequency impedance model driven from well logs and convolution of the reflection coeffiecients with a source wavelet derived from the seismic data. Acoustic impedance cross section obtained from the inversioin algorithim showed impedance values increasing from 4112 to 7539 (m/sec*g/cm 3 ) from top to bottom of the reservoir with gas filled sand facies observed at the top of the reservoir within time window 1900-2100msec. Below time window 2100msec, there is variation in impedance values observed within the anticlinal structures seen at this interval which suggests porous sand facies containing little shale intercalations. This is characteristic of sandstone reservoirs within the Agbada formation in the Niger Delta. These sands were most likely deposited through distributaries channel deposits, distributaries mouth bars, barrier bars, alluvial fans and crevasse which characterize the reservoir rocks (sandstones) in the Niger Delta. At time window 2100-2200msec, anticlinal structures containing porous sand facies with little shale intercalations was observed again. At time window 2200msec, water bearing sand facies (clean sandstone) was observed and at the bottom of the reservoir within time window 2300- 2500msec, the impedance was dominantly high which suggests the presence of shale facies at the bottom of the reservoir. Gas-oil contact (GOC) was observed between time window 2100-2200msec of the acoustic impedance section. These variations in acoustic impedance amplitude is due to lateral changes in lithofacies within the reservoir. The results obtained gave enhanced structural disposition of the reservoir and are important for accurate stratigraphic imaging interpretation to lower the risk in drilling of exploratory and development wells. Keywords : Acoustic impedance, Seismic inversion, Model-based, Lithofacies

Petrography of detrital zircons from sandstones of the Lower Devonian Accraian Formation, SE Ghana: Implications on provenance

Integrated petrographic studies entailing quartz‐type analysis and zircon typologic studies were carried out on sandstones of the Lower Devonian Accraian Formation of southern Ghana to constrain their provenance and tectonic setting. The stratigraphic succession of the Devonian Accraian Group consists mainly of sandstones in the Lower Accraian Formation, shales in the Middle Accraian Formation, and sandstone–shale intercalations in the Upper Accraian Formation. Systematic sampling of sandstones was conducted in the Lower Devonian Accraian Formation. Modal petrographic analysis indicates that the sandstones are quartz arenites with their framework grains consisting on average of, 99.8% quartz, 0.14% lithics with little or no feldspars. They are subangular to subrounded in shape. Modal mineralogy of the sandstones suggests that they are of craton interior origin with an affinity to recycled orogenic provenance. Quartz‐type analysis was used to unravel distinct characteristic features of the quartz grain, namely its polycrystallinity, nonundulose, and undulose nature to constrain the source rock. This pointed to multiple sediment supply from both a plutonic origin and a medium‐ to high‐grade metamorphic terrain. Furthermore, a comprehensive zircon typology study on 298 zircon grains indicate multiple provenances of calc‐alkaline affinity. This study revealed that the Lower Accraian Formation sandstones probably received sediment input from the Paleoproterozoic Birimian Basin granitoids and their associated metasedimentary rocks and some additional supply from the Neoproterozoic sedimentary rocks from the Volta Basin which are inclusive of sediments derived from the Dahomeyide Belt of the Pan‐African Orogeny.

Calcareous Nannofossils Biostratigraphy of the Lower Part of Balambo Formation (Lower Cretaceous) in Azmir Anticline - Northeastern Iraq

The present research includes a biostratigraphic study of calcareous nannofossils of the lower part of Balambo Formation (Lower Cretaceous) in Azmir anticline - northeastern Iraq. Lithologically, the lower part of the studied section (Balambo Formation) consists of limestone containing nodules of chert, marly limestone, with intercalations of green and gray-blue shale. In this work, it has been relied on calcareous nannofossils assamblages in biostratigaphy and age determination of this part because it does not contain planktonic foraminifera. First occurrences (FOs) and last occurrences (LOs) of marker species were used to identify biozones. The section was divided into four main biozones and two subzones and its correlation with collection from global, regional, and local biozones. Thus, the age of this part of the formation extends from the Late Early Hauterivian - Late Aptian. These are from older to younger: 1- Speetonia colligata Interval Zone (part) 2- Lithraphidites bollii Interval Zone 3- Micrantholithus hoschulzii Partial range Zone 4- Chiastozygus litterarius Interval Zone Hayesites irregularis Interval Subzone Eprolithus floralis Interval Subzone (part)

PERMEABILITY-POROSITY TRENDS IN CAWC RESERVOIR SANDS IN THE NIGER DELTA NIGERIA, USING WELL-LOG DATA

Reservoir characteristics analysis in the onshore Cawthorne Channel (CAWC) oil field, Niger Delta is here presented. The aim of the research was to assess reservoir properties and their relationships. A suite of geophysical logs comprising gamma ray, resistivity, neutron and density logs from eight wells were used in the analysis. Three reservoirs sands were delineated and linked across all eight wells. The litho-stratigraphy correlation section revealed that each of the sand units spreads over the field are differs in thickness with some units occurring at greater depth than their adjacent unit, that is possibly an evidence of faulting. The results show volume of shale values range from 11% to 17% indicating that the fraction of shale in the reservoirs is quite low. The total porosity of the reservoirs ranges from 0.22 to 0.39 indicating a very good reservoir quality and reflecting probably well sorted coarse-grained sandstone reservoirs. The permeability of the reservoirs ranges from 288 mD to 1250mD and this suggests good reservoir horizons. The hydrocarbon saturation of the reservoirs ranges from 0.59 to 0.71 indicating that the proportion of void spaces occupied by water is low consequently high hydrocarbon production. Sand-shale lithology was calculated, with sandstone volume decreasing with increasing depth, while shale volume increases with depth. Porosity and permeability showed decreasing trend with depth for both sandstone and shale units in all wells with few exceptions. This could be as a result of low compaction by overburden pressure from overlying rocks. Plot of lithology versus depth reveals that shale lithology increases with depth, while sandstone decreases. Lithology versus porosity plots show an inverse relationship between permeability and shale volume and direct relationship between permeability and volume of sand. Lithology versus permeability shows that permeability and shale volume have an inverse relationship whereas permeability and volume of sand have a direct relationship. Permeability decreases exponentially with decrease in porosity in rock matrix made up of intercalation of sandstone and shale. The modelled equation of permeability and porosity is given by K = 0.053e32.934Ф. This implies that in the absence of core and well-log data, permeability can be estimated using only porosity data. The results of this work can be used as an exploration tool for the identification of prospective areas and also for feasibility studies during an appraisal activity.

Determination of the Depositional Environment of Outcrop Section at Odoro Ikpe South Eastern Nigeria Using Pebble Morphometry

The depositional Environment of Odoro -Ikpe, South East Nigeria was interpreted using pebble morphometry and sieve analysis. A field observation, sieve analysis and pebble morphometric analysis was carried out on the area which comprises of conglomerate, pebbles, sand stone and intercalation of shale's and clay. The lithofacies observed are lateralitic layer, pebbly sand, alternating layers of sand and conglomerates and layers of massive sand stone. The graphic mean and skewness of the grain size analysis shows that the sediments are very coarse which indicates a high energy environment. Graphic standard deviation gives a clue that the sediment were very poorly sorted, which is indicative of a fluvial deposit with high energy , while kurtosis result revealed very coarse sediment deposits. This implies that the particles were not transported very far. Pebble analysis shows the geometric forms and this was deduced from the plot on shape measurement triangle. The shape is compact bladed which is common with river deposits. The bivarate plot of mean diameter against standard deviation also indicated a fluvial environment as well as bivarate plots of co-efficient of flatness against sphericity and maximum projection sphericity against oblate, prolate index which comprises of river and beach environment. All results showed or indicated that the environment of deposition was of river.

Shear creep characteristics of weak carbonaceous shale in thick layered Permian limestone, southwestern China

Several weak intercalations of carbonaceous shale, which are commonly developed in the Permian thick limestone strata in Wulong County, Chongqing, southwestern China, form a structure of alternating layers of soft and hard rocks, which control the stability of massive layered rockslides. We focus on the Permian carbonaceous shale and analyse its mineral composition, microstructure and shear creep characteristics during the three evolutionary stages. The analysis results indicate the following: (i) During the evolutionary process of the carbonaceous shale, the microstructure changed from compact to loose, and the clay mineral content gradually increased from less than 5% in the original soft rock to 5–10% in the interlayer shear zone, and finally to greater than 10% in the sliding zone. (ii) Under the identical shear stress, the creep displacement and rate gradually increase nonlinearly. Under the identical normal stress, the long-term shear strength gradually decreases, and the drop in cohesion is greater than the internal friction angle. (iii) We established an improved Burgers nonlinear damage creep model, which fully reflected the creep deformation process of the carbonaceous shale. The fitting curve of the model matched the experimental results well.

Geochemical characteristics of the Arbanos karst-type bauxite deposit, NW Iran: Implications for parental affinity and factors controlling the distribution of elements

The Arbanos bauxite deposit is located in the Iran-Himalayan karst-type bauxite belt and about 25 km northeast of Bukan city, northwestern Iran. The bauxite ores occur as layers and lenses along the contact of the carbonate (limestone and dolomite with intercalations of shale) of the Ruteh Formation (Upper Permian) and dolomite of the Elika Formation (Triassic). Hematite, kaolinite, and diaspore are the major rock-forming minerals in the ores, accompanied by lesser amounts of chlorite, montmorillonite, chamosite, siderite, goethite, boehmite, calcite, rutile, anatase, zircon, and quartz. Mass balance calculations indicate that the distribution of Ni, V, and Cr is controlled by the iron oxyhydroxides, whereas the distribution of Ba and Sr is controlled by kaolinite. The bivariate diagrams of the Sm/Nd versus the conservative elemental indices such as TiO2/Al2O3, Al2O3/Hf, Al2O3/Nb, and Nb/Ta reveal that the shale of the Ruteh Formation is the most plausible parent rock for the bauxite ores. The factor analysis method indicates that the paleo-environmental changes, soil redox state, and water activity in the pedogenic environments played a fundamental role in distribution of the major, minor, and trace elements.