Good Reservoir Quality Research Articles

Seismic Interpretation and Reservoir Static Model: A Case Study in Block MFK, Riau Province, Indonesia

MFK Block was located between Kampar and Rokan Hulu, Riau Province and 135 from Pekanbaru City, Indonesia. There are 33 wells in Field X, MFK Block with 27 active wells. This field has an area of about 79.65 km2 that located in Central Sumatra Basin. The field was discovered in 1976 and began to be produced in January 1979. Our research is focused on AK reservoir intervals, which is also part of Bekasap formation. The main aims of this study are to interpret field structure model, determine the distribution of reservoir properties, develop static reservoir model for field as a reference for field performance enhancement, estimate oil reserves in the field reservoir, and the prospect of hydrocarbons in the AK reservoir. The available data are 2D seismic data, mudlog descriptions, well log data, and perforation data. The methods used in this study are stratigraphic sequences, electrofacies analysis, geological structure analysis, static reservoir modelling, and estimation of hydrocarbon reserve volumes. Based on mudlog and electrofacies analysis, the study interval was arranged into 2 lithofacies units, namely sand channel and sand bar. The depostion environment of Bekasap Formation is estuarine environments. The interval of the study has an association of fasies moving northeast to southwest. Based on the results of property reservoir analysis, facies that have good reservoir quality is sand channel facies. Based on the static modeling method approach, the estimated stock tank oil initially in place (STOIIP) for AK reservoir interval is 728 MBBL.

E&P Notes (October 2022)

E&P Notes (October 2022)

Microfacies Analysis and Depositional Environments of Lower Sa’adi Formation, Southern Iraq

The Sa’adi Formation is a part of the late Cretaceous period in the Santonian-Campanian stage that represents a potential hydrocarbon-bearing reservoir across many oilfields in the Mesopotamian Basin, South of Iraq. The Formation was divided into two main parts as a stratigraphy sequence. It consists of chalky limestone with argillaceous limestone in the upper part and limestone with marly limestone in the lower part. The lower part is considered an important stratigraphic unit marked by petroleum shows. Thus, current research constructs the depositional environment, evaluates the reservoir, and predicts the best zones with good reservoir quality. The microfacies analysis was carried out on thirty-five thin sections to reveal the primary depositional environment, and well logs data were used to evaluate the petrophysical properties of the lower Sa’adi Formation. Four microfacies appeared related to the carbonate ramp, which identified the depositional system track from mid to inner ramp. These are; mudstone, wackestone, packstone, and grainstone. Twelve sub-microfacies were identified and interpreted in the lower Sa’adi Formation. These are pelagic lime mudstone to benthic foraminiferal-argillaceous wackestone in middle ramp experienced burial diagenesis and syngenetic diagenesis with intra-fossil pores. The results characterize the bioclast echinoderms, bivalves, and algae packstone to grainstone in inner ramp (open marine and shoal environments) experienced marine pore-water diagenesis, meteoric freshwater dissolution, and burial diagenesis. Shoal facies with open marine facies are the best favorable microfacies in the lower Sa’adi Formation. Diagenesis processes were represented by dissolution that improved the porosity and permeability with higher reservoir quality in the inner ramp; besides that, it was recognized that cementation and micritization reduced the reservoir quality in the middle ramp.

Assessment of hydrocarbon generation potential and thermal maturity of the deep offshore Lamu Basin, Kenya

In this study, the secondary well data for Cretaceous to Miocene cutting samples in four deep offshore exploration wells, i.e., Pomboo-1 in the north, Kubwa-1 in the central, Simba-1 and Kiboko-1 in the south of the deep offshore Lamu Basin were assessed for identifying source rock presence and examining thermal maturity of the source rocks. The 2D basin modelling was used to analyse the bulk gas transformation in the basin. Total organic carbon (TOC) content values for the wells range from 0.09 wt % to 2.23 wt % with an average of 0.78 wt %. The average organic richness is higher in the Upper Cretaceous (0.83 wt %) than in the Palaeogene (0.65 wt %), Lower Cretaceous (0.28 wt %) and Upper Jurassic (0.30 wt %). The S1 averages for the Upper Cretaceous are 3.76 mg HC/g rock in Pomboo-1 and 0.31mg HC/g rock in Kubwa-1. The S2 averages for the Upper Cretaceous are 5.00 mg HC/g rock in Pomboo-1 and 0.72 mg HC/g rock in Kubwa-1. Hydrogen index (HI) values vary between 4 and 512 mg HC/g TOC with an average of 157.09 mg HC/g TOC. Organic matters were identified as mixed types of II-III (oil and gas prone) and III-IV (gas prone) kerogen in the potential source rocks. The HI and S2 yield values are exceptionally high for the observed TOC values in Pomboo-1. The vitrinite reflectance and Tmax values of deep offshore Lamu Basin are in the ranges of 0.38%–0.72% and 360–441 °C, respectively. It suggests the existence of both immature and mature source rocks. Vitrinite reflectance maturity favours near coastal region in the Upper Cretaceous. These results explain why Pomboo-1, Kubwa-1, Simba-1 and Kiboko-1 wells were dry. The temperatures are still cool for hydrocarbon generation in deep offshore. The critical risk for deep offshore Lamu Basin is charge, primarily source presence, and a lack of definitive evidence of a deep-water marine source rock being present. The four wells penetrate good quality reservoir and seal rocks, but source rock presence and maturity remain the critical play risk in the deep offshore Lamu Basin.

E&P Notes (September 2022)

E&P Notes (September 2022)

3D forward stratigraphic modeling of the Albian succession in a part of the northeastern margin of the Arabian Plate and its implications for exploration of subtle traps

During the Albian age, siliciclastic input in the Arabian carbonate-dominated shelf formed important petroleum system elements. Hence, the Albian Burgan-Kazhdumi succession hosts world-class sandstone reservoirs in some Middle East oil fields. Moreover, stratigraphic traps are possible due to changes in facies and structural dips. Accordingly, we used process-based forward stratigraphy modeling as a powerful tool to predict Burgan-Kazhdumi units and de-risking new exploration prospects. A 3D stratigraphic model was constructed in this study for the first time by integrating multi-disciplines and multi-scales of seismic and well data from several countries. The model (324 km × 264 km, 4 km × 4 km grid size) encompasses NW of the Persian Gulf, Kuwait, south Iraq and SW of Iran and is vertically divided into three units based on Albian regional third-order sequences.Results indicated that the lower unit, unit-1, contains onlapping aggradational-retrogradational stacking compounds, high sand bodies thickness and distribution as well as good reservoir quality. This unit was deposited on a tide-dominated delta system. Gradually, with rising sea level, progradational fine-grain marine sedimentation dominated in units 2 and 3. Hence, intra-formational seal facies formed in the proximal and organic-rich facies in the distal intra-shelf areas. The gentle topography of the basin floor seems responsible for the lack of turbidity lobes. The sand bodies of up-dip arches such as Khafji-Norooz and Kharg-Mish highs and pinched out in fine-grained facies provide a significant potential for stratigraphic traps.The model sensitivity analysis showed eustasy, and water-driven diffusion coefficient (Kw) has the most critical impact on the clastic sedimentation of unit-1 and unit-3. Furthermore, tectonic events have the most significant sedimentation effect in unit-2 sedimentation.The findings of this study can help for better understanding of a more precise regional sequence stratigraphic and stratigraphic architecture of the Albian succession of the study area. This study also helps identify elements of petroleum plays as well as stratigraphic trap potential between mixed siliciclastic-carbonate depositional systems.

Reservoir quality evaluation using sedimentological and petrophysical characterization of deep-water turbidites: A case study of Tariki Sandstone Member, Taranaki Basin, New Zealand

The current study aims to ascertain the reservoir characteristics of the Tariki Sandstone Member of the Otaraoa Formation, Taranaki Basin, New Zealand. This study was carried out by integrating the comprehensive petrophysical evaluation, sedimentological and petrographic studies, as well as well log analysis by using data from six wells. The porosity-permeability relationship is used to divide the samples of the Tariki Sandstone Member into reservoir and non-reservoir facies. A thorough petrophysical analysis shows that the maximum porosity values fluctuate between 16.6% and 22.1%, while permeability ranges from 102 mD to 574 mD, which indicates fair to good reservoir quality. Moreover, the Tariki sandstone represents six hydraulic flow units with a high reservoir quality index and flow zone indicator representing good reservoir characteristics. The pore size varies between nano and megapores with dominant macropores. Based on the sedimentological and petrographic analysis, the Tariki Sandstone Member is classified as a combination of subarkose, arkose, and lithic arkose with fine to medium and moderately to moderately well-sorted grains. The main diagenetic factor affecting the reservoir quality is cementation, which occupied all the pores with calcite. On the bright side, the secondary pores are developed due to the dissolution of calcite cement and few grains. The well log analysis demonstrates the presence of low clay volume ranging from 0.3% to 3.1%, fair to good effective porosity values between 13.6% and 15.9%, net pay thickness from 18.29 m to 91.44 m, and hydrocarbon saturation from 56% to 77.9%. The findings from this study revealed that the Tariki Sandstone Member possesses fair to good reservoir quality and hydrocarbon potential, which indicate submarine fans as appealing hydrocarbon reservoirs. This study can be used in similar depositional environments elsewhere in the world.

Application of Hydraulic Flow Unit (HFU) and Windland R35 Methods in Sand-5 Reservoir, Field ‘S’, Talang Akar Formation, Asri Basin, Indonesia

The Sand-5 Reservoir in the Talang Akar Formation is the main oil and gas producer in the Field ‘S’, Asri Basin, Indonesia. Reservoir rock type (RRT) can be applied to optimize the performance of this reservoir. This study aims to compare the RRT methods between Hydraulic Flow Unit (HFU) and Windland R35 to find the best RRT method. Both methods utilized the porosity and permeability to classify the number of RRT, subsequently validated by the regression value (R2) of core permeability with predicted permeability. Four RRT values have been identified for both methods that are RRT-1 represent the very good reservoir quality, RRT-2 represents the good reservoir quality, RRT-3 represents the moderate reservoir quality and also RRT-4 represents the poor reservoir quality. The numbers of porosity and permeability for HFU method is 32-40% and 19.3-29.4 Darcy (RRT-1); 31-39% and 5.3-18.3 Darcy (RRT-2); 20-36% and 0.4-6.8 Darcy (RRT-3); 15-34% and 0.01-0.4 Darcy (RRT-4), while for Windland R35 method is 31-40% and 7.7-29.4 Darcy (RRT-1); 30-39% and 4-10 Darcy (RRT-2); 24-38% and 0.2-6.8 Darcy (RRT-3); 15-33% and 0.01-0.2 Darcy (RRT-4). Based on the relationship between core permeability and predicted permeability from each RRT, the result of the Winland R35 method is better than the HFU method.

Prediction of Cretaceous reservoir zone through petrophysical modeling: Insights from Kadanwari gas field, Middle Indus Basin

This study involved an interpretation of wire-line logs in assessing the hydrocarbon capacity of the sandstone reservoir within the gas fields of Kadanwari, Sindh, Pakistan. Wire-line logs from four wells (KD-01, KD-03, KD-10 and KD-11) were used in our research and provided interpretation for thirteen reservoir zones. Reservoir analyses were done for effective porosity (ϕeff), shale content (Vsh), net pay thickness variations, water saturation, and hydrocarbon (Sw and Shc). Hydrocarbon-bearing zones consist of high values of resistivity, permeability, porosity, low water saturation content, and less shale content, indicating the presence of clean sand. The Thomas Stieber model findings show that in lower Goru sand, the laminated form of shale distribution persists. Sub-reservoirs’ petrophysical parameters were analyzed and ranked into a good sand reservoir quality (having ϕeff ∼0.11-0.44%), permeability (∼10.539-477.76 mD), hydrocarbon saturation (having Shc ∼0.59-0.86%), and water saturation (having Sw ∼0.18-0.45%). In the current research Indonesian model has been used to test for water saturation over a shaly-sand reservoir situated in a heterogeneous zone. It was observed that each well exhibited Sw at values lesser than 60%. This is indicative the selected zone has a hydrocarbon potential, and the hydrocarbons are of good quality. Isoparametric maps and crossplots of litho-saturation results reveal variations in the horizontal and vertical petrophysical parameters of the reservoir. The subsurface reservoir geographical distribution is visualized employing isoparametric maps. The fuel treasure in the southwestern section of the study area is enormous, as revealed by the petrophysical investigations, suggesting more well-drilling prospects in the gas fields of the lower Goru Formation situated in Kadanwari. Our research identified a quality hydrocarbon hotspot zone of immense economic value in Southern Kadanwari. In contrast, more research is needed regarding the northeastern section though our present findings suggest the northeastern section should be avoided because of excess shale and high-water concentrations.

Characterization of the Lower Cretaceous Shale in Lishu Fault Depression, Southeastern Songliao Basin: Implications for Shale Gas Resources Potential

Large thickness of shales over 180.0 m was developed in the source rocks of the Shahezi and Yingcheng formations in the Lishu Fault Depression. Moreover, the high amount of gas content and the total hydrocarbon value of gas logging in several boreholes illustrate that there is a great potential of shale gas resources in this region. Therefore, an integrated characterization of shales from the lower Cretaceous Shahezi and Yingcheng formations was provided to evaluate shale gas resources potential. The measurement results illustrated that the organic-rich shale samples with kerogen type Ⅱ during high to over thermal maturity had a higher content of brittle minerals (>50%) and clay mineral dominated by illite. The shales had a total porosity of 3.11–4.70%, a permeability of 1.24 × 10−3–1.52 × 10−3 μm2, and possessed pore types including dissolution pores, inter-layer pores of clay minerals, micro-fractures, intra-granular pores, and organic pores, which were dominated by micropores and mesopores (0.5–1.7 nm, 2.2–34.3 nm) with a significant contribution from OM and clay minerals. According to the N2 adsorption isotherms, the pore volume was comprised primarily of mesopores with mean widths of 4.314–6.989 nm, while the surface area was comprised primarily of micropores with widths in ranges of 0.5–0.8 nm and 1.0–1.7 nm. Thus, the shales have a suitable porosity and permeability, indicating that fine storage capacity and favorable gas flow capacity occur in the Shahezi and Yingcheng formations, which exhibit a good reservoir quality and excellent exploration potential since the considerable thickness of shales could form a closed reservoir and served as cap rocks for in situ gas generation and accumulation. Especially, according to the measured CH4 excess adsorption amount and the calculated maximum absolute adsorption capacities of CH4 based on the Langmuir adsorption model, the estimated GIP values (1.388–3.307 m3/t) of the shales happened to be in a sampling depth under geological hydrostatic pressure and temperature conditions. This means that the shale storage capacity and high gas content from well site desorption completely met the standard of industrial exploitation when synthetically considering the GIP model. As a consequence, shales in the Shahezi and Yingcheng formations in the Lishu Fault Depression could be potential targets for shale gas exploration.

Shale Lithofacies and Sedimentary Environment of the Third Member, Shahejie Formation, Zhanhua Sag, Eastern China

AbstractResearches into shale lithofacies, their sedimentary environments and relationship benefit understanding both of sedimentary cycle division and unconventional hydrocarbon exploration in lacustrine basins. Based on a 100∼300‐m‐thick dark shale, mudstone and limestone encountered in the lower third member of the Eocene Shahejie Formation (Es3l member) in Zhanhua Sag, Bohai Bay Basin, eastern China, routine core analysis, thin sectioning, scanning electron microscopy (SEM), mineralogical and geochemical measurements were used to understand detailed facies characterization and paleoclimate in the member. This Es3l shale sediment includes three sedimentary cycles (C3, C2 and C1), from bottom to top, with complex sedimentary characters and spatial distribution. In terms of the composition, texture, bedding and thickness, six lithofacies are recognized in this succession. Some geochemical parameters, such as trace elements (Sr/Ba, Na/Al, V/Ni, V/(V + Ni), U/Th), carbon and oxygen isotopes (δ18O, δ13C), and total organic carbon content (TOC) indicate that the shales were deposited in a deep to semi‐deep lake, with the water column being salty, stratified, enclosed and reductive. During cycles C3 and C2 of the middle‐lower sections, the climate was arid, and the water was salty and stratified. Laminated and laminar mudstone–limestone was deposited with moderate organic matter (average TOC 1.8%) and good reservoir quality (average porosity 6.5%), which can be regarded as favorable reservoir. During the C1 cycle, a large amount of organic matter was input from outside the basin and this led to high productivity with a more humid climate. Massive calcareous mudstone was deposited, and this is characterized by high TOC (average 3.6%) and moderate porosity (average 4%), and provides favorable source rocks.

Paleoenvironmental and paleodepositional architecture of SAMO field in Niger-Delta Basin of Nigeria using seismic and well log data

The use of Seismic data and well log data within the context of sequence stratigraphy is a valuable tool for the recognition of ancient cycles and sequences because they reflect information on the different processes that deposit sediments in different palaeoenvironment. An integrated geophysical well log data and seismic data from our wells within the SAMO field have been utilized to delineate the upper Miocene-Pliocene depositional environment parts of the Niger-Delta Basin. Identification of the different lithologies and depositional environment present in the penetrated borehole was achieved using gamma ray log. This enables the establishment of different rock units in the well from the gamma ray log values and signatures. Three succession signatures which include; the bell, cylindrical and the funnel being more prominent were identified from the log motifs in the different sand bodies attenuated in the wells from the field. The mapped sequences generated Low stand System Tracts (LST) progradational, Trangressive System Tracts (TST) retrogradational and High stand System Tract (HST) aggradational packages. All these reflect the depositional systems that dominated the different phases as a result of base level changes. Furthermore, values quantified from the logs revealed that porosity and permeability are more prominent in places where sand bodies accumulated in the slope channel setting indicative of slope-fills and turbidity fans. This deep-sea channels and switch complex fault system suggest good hydrocarbon bearing potential associated with the distal Niger-Delta province. Also a good quality reservoir was inferred from the sands of both LST and HST while the shale of the TST could serve as a good reservoir.

Identification of Carbonate Reservoir Prospective Zones Using Rock Physics Approach and Extended Elastic Impedance (EEI) in “BAP” Field, South Sumatera Basin

One type of reservoir that has a large enough potential is the carbonate reservoir. Carbonate reservoir has heterogeneity in relation to pore shape, so it is necessary to apply a specific rock physics approach and seismic inversion which takes into account the elastic parameters of the rock in order to know the prospect zone of the carbonate reservoir. The rock physics approach taken is to estimate the modulus of the matrix and the estimation of the aspect ratio shows that the prospect carbonate has an aspect ratio range of 0.10 - 0.30 dominated by the pore shape of the Stiff Pore. Seismic inversion shows using extended elastic impedance shows carbonate porous (Mu-Rho < 33 GPa*g/cc) and saturated hydrocarbons (Lambda-Rho < 40 GPa*g/cc) are in the middle area (around the well) where the lateral spread is getting thinner with a thickness of up to 10 ms. The prospect zone analysis from rock physics modeling and extended elastic impedance shows that reef Baturaja Formation carbonate is a zone that has a good reservoir quality dominated by a pore shape that develops is stiff pore.

An integrated workflow for petrophysical characterization, microfacies analysis, and diagenetic attributes of the Lower Jurassic type section in northeastern Africa margin: Implications for subsurface gas prospection

The Jurassic sedimentary sequences are an important source and reservoir rocks in the North Africa margin, with its type section, outcropped at the Gebel El-Maghara massif and some other sites along the southern Tethys. These exposed Jurassic outcrops, of the intercalated continental and marine sediments, allow us to conduct more detailed and integrated studies on the various depositional settings with diverse lithologies as analogous for the subsurface reservoirs. The present study concerns the implication of the mineralogical components and the diagenetic controls on the petrophysical properties and the reservoir characteristics of the Lower Jurassic in Gebel El-Maghara outcrop sequence (from base to top Mashaba, Rajabia, and Shusha Formations) in north Sinai, Egypt. Some field trips were conducted, and samples were collected, to characterize the petrographical and petrophysical characteristics of these deposits using comprehensive standard techniques including studying thin sections, SEM imaging, XRD analysis, and various petrophysical measurements. A workflow is proposed to apply a full set of petrophysical measurements on the collected samples including porosity (∅He), permeability (k), grain and bulk densities (ρg and ρb, respectively), and true formation resistivity factor. In this workflow, we have integrated the petrophysical data with detailed microfacies analysis to reveal the implication of diagenesis on the reservoir quality of the Lower Jurassic reservoirs. The Lower Jurassic sequence is subdivided into five hydraulic flow units (HFUs) that consist of three reservoir rock types (RRTs). These RRTs are composed of three microfacies associations (MFAs). The RRT1 plug samples consist of the mostly clastic MFA1; they are porous, permeable, and have good reservoir quality that is using the flow zone indicator (FZI), and the reservoir quality index (RQI). The lowest reservoir quality is assigned to the RRT samples which are mostly composed of tight carbonates. Based on the petrographical studies, SEM imaging, and the XRD analysis, dissolution and fracturing slightly enhanced the reservoir potentiality of the RRT1 samples, whereas physical compaction, tight cementation, and authigenic clay content (kaolinite, hematite, and goethite) are responsible for the deterioration of the reservoir properties of RRT3 samples and reduction of the RRT2 samples. The study outcrop has the potential to be an excellent analogue for the important subsurface Jurassic gas-bearing deposits on the African's northern margins. Furthermore, it may provide insights into the fluid flow units, mineralogical composition, and diagenetic controls on the unique Lower Jurassic deposits of Gebel El-Maghara for the assessment of subsurface gas-bearing sequences in the nearby Mediterranean and Gulf of Suez from the southern Tethys shorelines.

E&amp;P Notes (March 2022)

E&amp;P Notes (March 2022)

An integrated approach of reservoir characterization of Y gas field in Central Bredasdorp Basin, South Africa

The study attempts to address the knowledge gap in the Bredasdorp Basin Offshore South Africa by using newly acquired seismic data with an enhanced resolution, integrating core and well log to provide a solution. The main objective of this study was a volumetric sandstone reservoir characterization of the 13At1 and 10At1 sandstones deposited in the upper shallow marine environment. The results reveal four facies grouped as facies 1(claystone), facies 2(intercalation of claystone and sandstone, facies 3(medium sandstone), and facies 4 fine-medium sandstone grain deposited in a deep marine environment. Facies 3, the medium-grained sandstone, has the best reservoir quality rock, while facies 1, which is predominantly claystone, has the least rock quality. The study has produced a calculated volume of gas in the 10At1 sand (upper and lower sand is 30.01 billion cubic feet (bcf)) higher than that of the 13At1 sand (27.22 bcf of gas). Improved seismic resolution enhanced the accuracy of results. It is advisable to focus further field development in the eastern part of the Y gas field because of good reservoir quality and production developed due to the sand in the 10At1 sequence.

Sequence Stratigraphic Interpretation of XY-Field Onshore Niger Delta Basin Nigeria

Wireline logs and biostratigraphic data were integrated to attempt the sequence stratigraphy of “XY field” onshore Niger Delta Basin which revealed three depositional sequences. Four sequence boundaries and three maximum flooding surfaces dated (17.7, 16.7, 15.5, and 13.1Ma) and (17.4, 15.9, 15.0 Ma) respectively were identified in both Wells. The delineated sequences comprised Lowstand Systems Tracts (LST), Transgressive Systems Tracts (TST) and Highstand Systems Tracts (HST), which reflect depositional systems deposited during different phases of base level changes. The sands of LST and HST show good reservoir qualities while the shales of the TSTs could form potential reservoir seals. Integration of lithofacies and biofacies data suggests that the depositional environments ranges from transitional to Outer Neritic environment.

Application of 3D Static Modelling in Reservoir Characterization: A Case Study from the Qishn Formation in Sharyoof Oil Field, Masila Basin, Yemen

AbstractThree‐dimensional (3D) static modelling techniques are applied to the characterization of the Qishn Formation (Fm.) in the Sharyoof oil field locating within the Masila basin, southeastern Yemen. The present study was initiated by the seismic structural interpretation, followed by building a 3D structural framework, in addition to analysing well log data and from these, 3D facies and petrophysical models are constructed. In the Sharyoof oil field, the Qishn Fm. exhibits depth values within the range of 400–780 m below sea level, with a general increase towards the SSE. A set of high dip angle normal faults with a general ENE–WSW trend dissect the rocks. The strata are also folded as a main anticline with an axis that is parallel to the fault trend, formed as a result of basement uplift. According to the facies models, the Qishn Fm. comprises 43.83% limestone, 21.53% shale, 21.26% sandstone, 13.21% siltstone and 0.17% dolomite. The Qishn Carbonates Member has low porosity values making it a potential seal for the underlying reservoirs whereas the Upper Qishn Clastics S1A and C have good reservoir quality and S1B has fair reservoir quality. The Upper Qishn Clastics S2 and S3 also have fair reservoir quality, while the Lower Qishn Clastics zone has good reservoir quality. The water saturation decreases towards the west and east and increases towards north and south. The total original oil in‐place (OOIP) of the Upper Qishn clastics is 106 million STB within the S1A, S1C and S2 zones. Drilling of development wells is recommended in the eastern study area, where good trapping configuration is exhibited in addition to the presence of a potential seal (Upper Qishn Carbonates Member) and reservoir (Qishn Clastics Member) with high porosity and low water saturation.

E&amp;P Notes (February 2022)

E&amp;P Notes (February 2022)

Reservoir characterization of fluvio-deltaic sandstone packages in the framework of depositional environment and diagenesis, the south Caspian Sea basin

The Middle Pliocene Fasila and Balakhany Suites are important petroleum-bearing reservoirs in the South Caspian Basin. There are four lithofacies associated with the interbedded sandprone reservoir intervals. The mineral constituents, sedimentary structures and depositional setting of the productive interval are interpreted as river-dominated depositional setting, including conglomeratic facies relating to a channel floor sub-environment and sandstone facies associated with the upper parts of river channels. The drainage basin of the Volga River is considered as the provenance for these deposits derived from basement rock outcrops to the north, which belongs to the Russian Precambrian semi-oceanic continental platform. Reservoir quality is assessed using the core-based porosity and permeability data in relation to the sedimentary and diagenetic processes influencing each lithofacies. Lithofacies 1 and 2 have good reservoir quality, while lithofacies 3 and 4 have poorer reservoir quality. Reservoir quality is controlled by both depositional setting (grain size and texture) and diagenetic imprints associated mainly with compaction, cementation and neumorphism. The role of clay minerals in the diagenesis of the sandstones with increasing burial depth is revealed by SEM and XRD analysis. Clay minerals progressively alter to illite, smectite and chlorite with increasing burial depth. This alteration leads to the occlusion of pore throats and degrading reservoir permeability.