Good Reservoir Research Articles

An Integrated Geological Model of Selective Carbonate Reservoir Wells, in Mishrif Formation in the Ratawi Oilfield, Southern Iraq

The majority of petroleum studies have traditionally focused on rocks that store hydrocarbons due to their economic significance, particularly in a period where oil is the primary global energy source. In the Cretaceous period, Iraq, and the Middle East, in general, are of particular interest due to the presence of formations that are significant for hydrocarbon storage and generation. The Mishrif Formation, dating to the Cenomanian-Early Turonian period, is a notable oil reservoir in southern Iraq. This formation’s distinctive features and extensive surface area make it a significant hydrocarbon repository, ranking second economically after the Zubair Formation in the region. This study analyzed six oil wells from the Mishrif Formation using various well logs (gamma ray, density, neutron, spontaneous potential, acoustic and resistivity) to extract petrophysical properties. The study identified rock types, layer boundaries, thicknesses, formation depths, and hydrocarbon-bearing zones. Through qualitative interpretation of these logs, the reservoir's characteristics were evaluated, including porosity, shale distribution, water and oil saturation. The results were visualized in three-dimensional models using the Petrel software, showing the distribution of these characteristics across the study wells. The Mishrif Formation is composed of four units (MA, CR-1, MB-1, and MB-2), with varying properties that were detailed in this study. Shale volume, averages between 0.04 % and 0.16%. Effective porosity ranges from 0.09% to 0.19%, indicating good reservoir quality; permeability ranges from 0.001 to 10 MD. Hydrocarbon saturation varies from 0.1to 0.7, while water saturation ranges from 0.3 to 0.9. The distribution of effective porosity in the Middle Mishrif reservoir unit is good throughout the field. In the Lower Mishrif reservoir unit, the effective porosity distribution is good in the central part of the field but poor in the northern and western parts. The formation thickness is homogeneous, indicating stable deposition. Hydrocarbon accumulations are present in both the Lower and Middle Mishrif reservoir units.

Determining Petrophysical Properties Using PLTs and Conventional Logs of the Middle Shale Member (4th Pay) of the Zubair Formation in the South Rumaila Oil Field, Southern Iraq

The petrophysical evaluation of the Zubair Formation's Middle Shale member (4th Pay) in the South Rumaila oil field has been conducted to characterize the reservoir and quantify its hydrocarbon prospects. Although the 4th Pay has a substantial oil reserve, it has never been studied. A gamma ray, resistivity, density, and neutron log were used to estimate the shale volume, porosity, water saturation, and hydrocarbon saturation for four oil-bearing subunits in the middle shale member (4th Pay), producing net pays of Middle Shale Member 7 (13 m), 10 (31 m), 20 (11 m) and 25 (16 m), respectively. Shale volume calculated using the Gamma-Ray Log method, averages between 0.05 % and 0.53 %. Effective porosity ranges from (0.08) % to (0.21) %, indicating good reservoir quality; permeability ranges from 0.9 to 193.6 mD, indicating well-sorted sands. Hydrocarbon saturation varies from 0.29 to 0.89, while water saturation ranges from (0.11) to (0.72). Production Log Tool and Nuclear Magnetic Resonance logs were used to estimate permeability. Production Logging Tool log permeability values ranged between 5.2 (Middle Shale Member 10, 3425 mD) and 49.7 (Middle Shale Member 25, 3448.5 mD), while Nuclear Magnetic Resonance log permeability values ranged between 5.81 (Middle Shale Member 10, 3425 mD and 49 (Middle Shale Member 25, 3448.5 mD). According to the correspondence between the two logs, the correspondence value equals 85%. Thus, the reservoir permeability can be calculated using the radial flow equation calculated from the Production Logging Tool log and generalized to areas where there is no core. Results show that permeability (K) is highest in subunits Middle Shale Member 20 and 25, which also have high porosity, low shale content, and fine grain sorting, making them key production subunits. Subunit Middle Shale Member, although lower in permeability, is the main reservoir with the most oil reserves. Subunits Middle Shale Member 5 and 7 have lower permeability due to high shale content and heterogeneity, with low porosity. Subunit Middle Shale Member 0 has very low permeability. The high oil shale content, due to its poor porosity and heterogeneity, renders it unproductive.

Analysis of the reservoir properties of rocks of the Lower Kura depression (Azerbaijan)

The article analyzes the features characterizing the Lower Kura depression (LKD). A number of hydrocarbon deposits have been discovered in this oil and gas region. The Kalmas underground gas storage facility, which has the largest volume in Azerbaijan, is also located in this area. In the LKD, all PS formations can be traced throughout the entire well section. The reservoir properties of the rocks were considered to study the features of the area. In order to study the reservoir properties in the well section, the field applies data obtained by using a complex of well logging (WL) methods (laterolog, spontaneous potential logging, induction logging, gamma logging, neutron logging, acoustic logging) and analyses of rock samples. The graphs were constructed to evaluate the relationship between petrophysical parameters (porosity, permeability, etc.) determined in the rocks involved in the well sections of the object of research. In the article, maps of porosity distribution, permeability and permeability of sandy siltstone rocks and fractions greater than 0.1 of the Productive Series of the South-Eastern Gobustan and Baku Archipelago, which are part of the Low Kura Depression, are plotted and analysed. Plots showing the porosity distribution of the Low Kura Depression by depth were also constructed and some results were obtained. Based on reservoir properties, the region is divided into 6 groups, and in each group intermediate values of the porosity and permeability coefficient are determined. In general, the porosity coefficient ranges within 5-25%, permeability – 1-250 mD. The reservoir properties of rocks vary over area from worse to better. The capacitance-filtration properties of rocks were studied. The rock samples analysed identified rocks with good and low reservoir characteristics. To study the variation in the determining factors, maps of the distribution of reservoir properties indicators (fractions greater than 0.1 mm; porosity and permeability in sand-siltstone-containing rocks) were compiled by area and their causes were determined by comparison with other oil and gas fields. It was found that with distance from the mouth of the Kura River (towards the right and left banks), the reservoir properties of the rocks deteriorate. This is due to an increase in the amount of clay in rocks. It is also clarified that the change in porosity coefficient does not depend on depth. The content of sand-siltstone composition in the rocks along the section is 20-50%.

Petroleum system analysis of Fujairah basin, eastern offshore of the United Arab Emirates

The Fujairah basin, located on the eastern margin of the United Arab Emirates, forms part of the hinterland basin of the Oman-UAE mountains. Despite its geological significance, the hydrocarbon potential of this basin remains unexplored. This study aims to address this knowledge gap by using 2D seismic reflection data, three exploration wells, geochemical data from one well, a 2D velocity section, and two pseudo-wells. The study began with the interpretation of the seismic profiles and then proceeded to create depth maps for the most significant units. We used Rock-Eval pyrolysis plots to identify the primary source rocks and to classify their kerogen types. The seismic interpretation formed a basis for the 1D and 2D basin modeling techniques that are used to determine the petroleum system of the basin. Our results identify the Pliocene, Miocene, and Eocene sequences as potential source rocks in the basin with TOC values less than 1 wt% and low expulsion efficiencies. The Pliocene and Miocene source rocks are mainly type-II kerogen, whereas most Eocene samples are characterized as type-III kerogen. The Pliocene and Miocene source rocks are immature in the basin. The Eocene is mature depending on the burial within the sub-basins. The Eocene started expelling hydrocarbons during the Burdigalian, which was linked to the collision of the Arabian and Central Iran plates along the Zagros suture zone. Structural and stratigraphic traps may have entrapped the generated hydrocarbons. The three drilled wells in the basin lack good reservoir rocks. However, low-velocity anomalies and bright spots indicate possible hydrocarbon accumulations in the basin.

Remediation quantum of organic amendments to immobilize potentially toxic heavy metals in wastewater-contaminated soils through maize cultivation

Wastewater is considered a good reservoir of mineral elements that can be used for agriculture, aquaculture, and some other activities after adopting suitable measures. The gap between supply and demand for water is increasing exponentially because of the abrupt boost to the world’s population. This poses a threat to human life as it has reached alarming levels in some parts of the globe. Normally, wastewater consists of liquid waste produced by commercial or industrial sources for daily use, consumption, and production. It is time to refocus our attention on a kind of circulating water system by reusing municipal wastewater for agricultural purposes, particularly irrigation. The recycled or treated water would be used as an alternative to fresh water. In the current study, the impact of various organic amendments was studied to mitigate the toxic effects of pollutants present in wastewater by cultivating maize as a test crop. The present study comprised five treatments replicated four times with a randomized complete block design under field conditions. In this experiment, the treatments included T1 (treatment 1) = control (wastewater-polluted soil without the application of any amendment), T2 = farmyard manure (FYM) at 2.5 tons ha-1 (hectare-1), T3 = FYM at 5.0 tons ha-1, T4 = compost at 2.5 tons ha-1, and T5 = compost at 5.0 tons ha-1. The application of FYM at 5.0 tons ha-1 (T3) was recorded as being the most effective as the maximum improvement was observed in soil characteristics such as pH, electrical conductivity (EC), sodium adsorption ratio (SAR), and organic matter, and for T3, these were 7.33, 2.22 dS m-1, 8.16, and 0.94%, respectively. T3 remained most superior in reducing the concentration of heavy metals in the soil; for example, lead, cadmium, nickel, and arsenic for T3 were 8.64, 1.34, 10.44, and 2.25 mg kg-1 (milligrams per kg), respectively. Maximum fresh biomass (fodder yield) of 9.98 tons ha-1 was harvested when FYM was applied at 5.0 tons ha-1 to the soil compared to 6.2 tons ha-1 in the control plot. The highest contents of nitrogen (1.20%), phosphorus (0.41%), and potassium (3.97%) were observed in maize plants for T3. In maize plants (T3), the concentration of lead, cadmium, nickel, and arsenic was reduced to levels of 1.92, 0.23, 2.28, and 1.25 mg kg-1, respectively. Therefore, it can be concluded from the findings of the experiment that the application of FYM significantly reduced heavy metal concentrations and improved soil health, along with maize crop growth and productivity.

Bioprospecting for sustainable and eco-friendly bioproducts: A case study of multi-enzyme production by soil microbes

Microbial multi-enzyme production is a promising research area involving microbes that can simultaneously synthesize numerous enzymes for the degradation of substrates with environmental sustainability and other industrial applications as the focus. During this study, we isolated, screened, and identified some multi-enzyme-producing microbes from three soil sites in Ibadan: Apete Dumpsite (ADS); Botanical Garden University of Ibadan- (BGUI); and Eleyele Cassava Processing Field- (ECPF). Precisely 500 g of soil were collected per point at different depths (0–10, 10–20, and 20–30 cm) and further analyzed. The microbial load and type and enzyme assays were determined. The highest average microbial count (6.9 × 108 CFU/g) was recorded in the ECPF soil sample at 0–10 cm depth, while the lowest microbial count of 3.3 × 105 CFU/g at 20–30 cm soil depth in BGUI. Multi-enzyme-producing microbes were identified phenotypically and molecularly. This study revealed an inverse relationship between microbial community composition and soil depth. Bacterial and fungal genera had higher species richness, biodiversity, and evenness than yeast from all sampled points. With significant amylolytic, proteolytic, lipolytic, cellulolytic, and pectinolytic activities, 22 of the 193 isolates were identified as multienzyme producers. The blasted 16S rRNA and ITS rRNA amplicon sequences compared with sequences in the NCBI gene bank identified Bacillus, Roseomonas, Aeromonas, Phanerochaete, Aspergillus, Fusarium, Trametes, and Rigidoporus species. Results from this study show that topsoils (0–10 cm), rich with organic matter, are good reservoirs of multienzyme-producing microorganisms- applicable for environmental sustainability and in other important industries for waste management, food processing, and biomaterial production.

Application of Seismic Sedimentology in Identifying Submarine Fan Bodies

Abstract The research area is located in the Yenisai Hatanga Basin of Russia, which is a transitional facies sedimentary rock between sea and land. Oil and gas are mostly concentrated in turbidite sand bodies of the low level domain submarine fans of Lower hutt formation in the Lower Cretaceous, and locally developed in the slope fan sand bodies of the high postion domain. which is good oil and gas reservoir, however, due to limitations of geological research conditions and data, the sedimentary characteristics and planar distribution of the submarine fan sand bodies are not clear in research area. This article conducts research on the identification and plane distribution prediction of submarine fan bodies using seismic sedimentology methods, By combining sequence stratigraphy, seismic profile, and RGB fusion technology, the sand bodies of submarine fans are analyzed. Through the correlation analysis of seismic profiles and seismic facies, corresponding relationship between sedimentary microfacies and typical seismic wave patterns is established. The study shows that the study area mainly develops continental shelf slope facies, submarine fans, and shallow to semi deep marine facies. Sediments formed a turbidite submarine fan composed of sandstone siltstone mudstone in the ancient trough. There are 5 sand groups developed in the Hutt Formation under the main target layer in the study area. Among them, the IV oil group is the main oil-bearing layer. The 0, Ⅰ, and Ⅱ sand groups have limited distribution and poor sand body connectivity. The Ⅲ sand group is mainly developed in the study area. In the north, it is distributed in the middle of the study area on the plane. The IV sand group is widely developed and distributed in the middle of the study area on the plane. Seismic sedimentology can provide technical support for prediction research of reservoirs.

Differences in reservoir quality within distributary channel belts at the braided river delta front in the Xinchang area of Western Sichuan’s 2nd member of the Xujiahe Formation: genesis and implications

The tight sandstone reservoris are important exploration and production target in the Xujiahe Formation in Xinchang area of Western Sichuan. Due to the various lithofacies and diagenetic alteration in distributary channel belt sandstones, the reservoirs exhibit strong heterogeneity. The strong heterogeneity makes the identification of petrologically superior sandbodies a great challenge. In order to better understand reservoir quality, this study constructs a model between diagenetic alterations and reservoir quality within distributary channel belts. 73 plug samples were taken from 17 wells located in the channel belt. An integration of thin sections, X-ray diffraction, carbon and oxygen isotope ratios, cathodoluminescence, and micro-CT were analysed for the genesis and distribution of reservoir quality. The results show that subaqueous distributary channels are formed under various hydrodynamics, resulting in different lithofacies. The thicknesses of channels can be divided into less than 2 m, 2–6 m, and more than 6 m. The diagenetic alteration in lithofacies were identified. Coarse-grained sandstones with low content of rock fragments are relatively weakly compacted with less calcite and chlorite cementation. Fine-grained sandstones with high content of rock fragments are strongly compacted with calcite cementation during early diagenesis. The dissolution pores are related to the soluble mineral content and the distribution of mudstones. The subaqueous distributary channels formed in high-energy, moderate-energy, and low-energy hydrodynamic settings have experienced different diagenetic intensities. Additionally, fractures can effectively improve the reservoir properties. The distribution of good quality reservoirs is controlled by the combined influence of diagenetic heterogeneity and fractures. This would help to promote better understanding of reservoir quality within the subaqueous distributary channel belts in braided-river delta front.

Integrated seismic, petrophysical, and geochemical studies for evaluating the petroleum system of the Upper Bahariya-Abu Roash G sequence in the Karama Field, Abu Gharadig Basin, North Western Desert, Egypt

The main aim of this study is to delineate the hydrocarbon potential and evaluate the petroleum system elements of the Cenomanian Abu Roash G (AR/G) and the Upper Bahariya Members in the Karama Field. It lies at the southeast borders of the Abu Gharadig Basin, a well-known basin in the W.D. to the NE of Africa. We accomplish this study by analyzing a total of thirty 2D seismic profiles, a complete data set of well logs for five wells, and their geochemical data. The workflow starts with illustrating the dominant subsurface structural features, defining the main potential reservoirs and their parameters, and checking the maturity of the probable source rocks. The seismic interpretation indicated that the research area had been influenced by a NE-SW anticlinal structure accompanied by a set of WNW-ESE and NW-SE normal faults that are controlled by the positive compression inversion process that dominated during the Late Cretaceous. Analyzing and processing the well log data sets suggest that the reservoirs of the Abu Roash G (AR/G) and the Upper Bahariya Members are characterized by poor to good reservoir settings with net-pay thickness reaching up to 13–50 feet in the different wells (av. Effective porosity (∅eff) = 17.7 % and 15.6% for the AR/G and the Upper Bahariya Members, av. Shale volume (Vsh) = 17.4 % and 13.6 %, av. Water saturation (Sw) = 38.9 % and 39.8 %, while av. Hydrocarbon saturation values (So) = 60.2 % and 61.1%, respectively). The geochemical and maturity analyses assisted in determining the potential mature source rocks of the Jurassic Khatatba Shale (TOC = 0.70–5.67%; S1+S2 = 0.43–5.97 mg/g, Ro = 0.54–1.06 %) with some contribution from the Cretaceous sources (Alam El-Bueib and Bahariya Formations). Studying elements of the petroleum regime of the Karama Field indicates that the trapped hydrocarbons are structurally controlled by three-way dip closures, horst blocks, sealing faults, and vertical sealing by impervious shale and limestone beds. This case study could be applied to similar analogs in other oil fields in the Egyptian Western Desert to delineate their hydrocarbon potential and structural setting.

The role of the Messinian evaporites in the identification of potential gas storage sites: A review of the Adriatic foreland basin system (Italy)

AbstractFocusing on the late Miocene succession stratigraphic successions including the evaporite deposits from the Messinian salinity crisis (MSC) of the Adriatic foreland basin, a revision of available boreholes and seismic data allowed us to recognize the presence of reservoirs and seals systems that can be considered of potential interest for the storage of natural and synthetic gas. Potentially good reservoir sites can be found where porous rocks referable to siliciclastic turbiditites (Marnoso‐arenacea and Laga Fms) or shallow‐water carbonates (Bolognano Fm) preferentially involved in anticlinal structures and covered by thick MSC evaporites, which may represent effective reservoir seals. The integrated reconstruction of porous rocks distribution and facies, thickness, and lateral continuity of the overlying evaporites, allows the identification and zonation of geological settings in the Adriatic foredeep, backbulge and foreland with peculiar stratigraphy and deformations, only partially considered before, that may deserve consideration in the research of potential gas storage sites.

A Petrophysical Properties Evaluation Study of a Niger Delta Field Using Well Logs and Core Data

A petrophysical properties evaluation study of an onshore field “NEMA” was carried out to assess the petrophysical characteristics of the field in the eastern portion of the Niger Delta Basin. This was done in an effort to determine the hydrocarbon prospect and oil productivity potential of the reservoirs. The net/gross thickness was one of the examined parameters. (pay zone thickness), porosity, permeability, fluid saturation which were all inferred from geophysical wireline logs and core data. The wireline logs used in the investigation included density, resistivity, gamma ray, and spontaneous potential logs for five different wells from the “NEMA” oil field. Five reservoirs designated, NEMA 01, NEMA 04, NEMA 07, NEMA 09, and NEMA 12 were identified and correlated across the five wells in the field using gamma ray logs and shale resistivity markers. Based on the computation of petrophysical parameters, the porosity of the reservoirs ranged from 0.22 (22%) to 0.31 (31%); the permeability ranged from 851.58 mD to 1005.05 mD; the average net-to-gross thickness of the reservoir sand bodies was 140 ft; the water saturation value was less than 45%, while the hydrocarbon saturation was greater than 55%. We equally observed that our computed petrophysical parameters from well log data correlated well with the core computed values in NEMA 09. In conclusion, the delineated reservoirs were categorized as good hydrocarbon reservoirs. These results suggest huge hydrocarbon potential and a reservoir system whose performance is considered satisfactory for hydrocarbon production.

Unraveling the Hidden Potential of Barley (Hordeum vulgare): An Important Review.

Barley (Hordeum vulgare) is a winter crop well known for its small-seeded grains and self-pollinating characteristics. The flour derived from barley grains plays a crucial role in numerous processed food items, contributing to their taste and nutritional value. Barley consists of complex carbohydrates (80%), proteins (11.5-14.2%), lipids (4.7-6.8%), β-glucans (3.7-7.7%), and ash (1.8-2.4%). Beyond its other nutrients, barley boasts a good reservoir of phenolic compounds (1.2-2.9 mg/g GAE). This abundance of beneficial compounds positions barley as an attractive industrial substrate. In this review, the nutritional composition and bioactive profile of barley are discussed in a systemic manner, emphasizing its potential in the development of innovative barley-based products that promote health and well-being. By incorporating barley into various food formulations, industries can not only boost nutritional content but also offer consumers a wide range of health benefits. In conclusion, barley's diverse applications in food and health highlight its essential role in promoting healthier living.

Facies controls and tectonic evolution on oil accumulation and entrapment in the Cenomanian Abu Roash G member, northern-central Egypt: Deltaic and channel sandstones as good reservoirs

Along northern-central Egypt, the oil accumulation and entrapment were mainly controlled by variable parameters including the stratigraphic architecture, sedimentary features, and tectonic evolutions. The present paper presents a new model for oil occurrences in the Abu Roash G Member (Cenomanian) along Gindi, Abu Gharadig and to a few extents the Beni Suef basins, in the northern-central part of the Western and Eastern Deserts of Egypt. The studied concessions include the Wadi El Rayan, East Bahariya and El Diyur (Gindi basin and Abu Gharadig basins, Western Desert) and the Ghariboun (Beni Suef Basin, Eastern Desert) fields. Twenty sedimentary facies were recorded from the studied subsurface sections of the Abu Roash G Member and grouped into three facies associations. A new depositional model is achieved where estuarine, open marine, deltaic distributaries, and tidal channel deposits are the main facies associations recorded in the studied Abu Roash “G". These deltaic and channel deposits occurred as an arch like form between open marine and estuarine deposits. These deltaic and tidal channel sandstone deposits act as a good reservoir to accumulate oil from nearby areas. As well, these areas were subjected to the well-known Syrian arch compressional deformation that affected northern Egypt during the Mesozoic, up to late Senonian time. A regional NE-SW oriented fold system took place, forming NE-SW oriented ridges in addition to the dextral strike-slip movement that took place along these ridges because of this compressional deformation.To sum up, oil accumulation in the studied Abu Roash G Member was mainly controlled by facies distribution mainly of channel sandstone enhanced by the tectonic movements (Syrian Arc System) affecting the areas studied.

Seismic Inversion Techniques and Attribute Analysis for Accurate Well Placement in Offshore Niger Delta Basin, Nigeria

Before this study, simple methods like seismic attribute analysis have often been used for reservoir characterization with successes however, there is still the need to reduce exploration uncertainty to a negligible level and boost investors’ confidence. This study integrated seismic inversion with seismic attribute analysis to better characterize the reservoirs in MTW Field in deep-offshore Niger Delta Basin. Five (5) wells with complete suite of petrophysical logs, three-Dimensional (3-D) seismic data, checkshot and other well information were used. The well data were thoroughly quality checked, reservoirs were litho-stratigraphically delineated and used for petrophysical analysis across the wells. This was followed by seismic-to- well-tie, seismic interpretation, and seismic attribute analysis (Root Mean Square-RMS) generated using depth surface maps. 3-D static reservoir model and volumetric evaluation were carried out. Petrophysical properties were derived and distributed across the 3-D static model using sequential gaussian simulation algorithm to ascertain shale volume spread across the model. To improve the seismic resolution and reduce interpretation uncertainty at greater depth, model- based post-stack seismic inversion was performed to obtain acoustic impedance cube. Litho-stratigraphic and petrophysical analysis result revealed five reservoir sands (A, B, C, D, and E). Reservoir-A was seen to be more viable with a thickness of 13.42 m, high effective porosity of 27%, permeability of 3187.53 mD, low water saturation of 34% and low shale volume of 11% which are indication good reservoir quality and producibility. The seismic interpretation revealed thirty-one (31) growth and antithetic faults oriented in the NE-SW and NW-SE directions, respectively. The RMS result revealed high amplitude reflectivity which is a measure of zone of interest. Based on this, seven (7) prospects and three (3) leads were identified. The seismic inversion result shows a high level of accuracy with a correlation coefficient of 0.997; 0.997; 0.995; and 0.996 in MTW-001, MTW-003ST1, MTW-004ST1 and MTW-005 wells, respectively. The acoustic impedance successfully resolved and improved on the resolution of the seismic stacking velocity especially at reservoir layers and at depth deeper than 3600 ms. Acoustic impedance as a layer property has improved on the lateral and vertical resolutions of the data beyond what the usual seismic interval velocity could image thus, validating some of the prospects and leads identified in this study. This demonstrated that uncertainty can be reduced by a blend of RMS and seismic inversion in identifying reservoir for accurate placement of wells. It is therefore recommended that E and P operators should adopt the technique in their future hydrocarbon exploration endeavor in frontier and matured basins.

Identifying payable cluster distributions for improved reservoir characterization: a robust unsupervised ML strategy for rock typing of depositional facies in heterogeneous rocks

The oil and gas industry relies on accurately predicting profitable clusters in subsurface formations for geophysical reservoir analysis. It is challenging to predict payable clusters in complicated geological settings like the Lower Indus Basin, Pakistan. In complex, high-dimensional heterogeneous geological settings, traditional statistical methods seldom provide correct results. Therefore, this paper introduces a robust unsupervised AI strategy designed to identify and classify profitable zones using self-organizing maps (SOM) and K-means clustering techniques. Results of SOM and K-means clustering provided the reservoir potentials of six depositional facies types (MBSD, DCSD, MBSMD, SSiCL, SMDFM, MBSh) based on cluster distributions. The depositional facies MBSD and DCSD exhibited high similarity and achieved a maximum effective porosity (PHIE) value of ≥ 15%, indicating good reservoir rock typing (RRT) features. The density-based spatial clustering of applications with noise (DBSCAN) showed minimum outliers through meta cluster attributes and confirmed the reliability of the generated cluster results. Shapley Additive Explanations (SHAP) model identified PHIE as the most significant parameter and was beneficial in identifying payable and non-payable clustering zones. Additionally, this strategy highlights the importance of unsupervised AI in managing profitable cluster distribution across various geological formations, going beyond simple reservoir characterization.

Sedimentary and Tectonic, Implications on Late Cretaceous Reservoir Succession Along the Oil Fields, Mosul Block, Northwestern Iraq

This study focuses on Cretaceous reservoir succession development and evaluated in the Mosul Block NW Iraq. The oil fields are Sufayia, Ain Zalah, and Tel-Hajer (Sufayia-1, Ain Zalah-29, producing fields and Exploration well Tel-Hajar-1 South of Jabal Sinjar-non producing field). The Mosul Block in Northwestern Iraq has Cretaceous reservoirs, but less research has been done on the deeper plays of the Lower Cretaceous, Jurassic, and older reservoirs. Non-Tertiary reservoirs in this zone are unlike what exists in eastern Iraq. The reservoir facies and Stratigraphy evolution are influenced by three tectonic development phases: Phase I (Late Albian to Cenomanian): The Gir Bir Formation The main reservoir exhibits good hydrocarbon efficiency reservoir, characterized by Shoal Rudist and benthic foraminifers. Notably, this formation is absent in Tel-Hajar. Phase II (Turonian to Late Campanian, obduction phase): Tel-Hajar structure South Jabal Sinjar, as positive region (Austrian orogeny) which uplifts the Wajnah Formation Sub basinal, Facies overlying the Mushorah Formation in Ain Zalah and Sufayia fields. Phase III (Late Campanian to Maastrichtian), fractured basinal facies Shiranish Formation reservoir, located in the northern parts of Mosul Block Ain Zalah and Sufayia fields. However, no reservoir of cretaceous of Tel Hajar-1. The study concludes that the oil fields northwest of Mosul Blocks (Sufayia and Ain-Zalah fields) have good potential produced from the Cretaceous reservoir, while the south of Mosul Blocks well (Tel-Hajer -1) has weak potential as cut-out cretaceous stratigraphy (pale high) Cretaceous stage.

Petrophysical Characteristics of Mauddud Formation in Selected Wells of Ratawi Oilfield, Southern Iraq

The Mauddud Formation is the most widespread Lower Cretaceous formation in Iraq, deposited along the NE margin of the Arabain Palte. The formation is widely distributed, covering nearly the entire territory of Stable and Unstable Shelf units. The study area is located in the Zubair subzone of the Mesopotamian zone within the Stable Shelf unit, approximately 70 km northwest of Basrah in southern Iraq. The main goal of this study is to evaluate the petrophysical characteristics of Mauddud Formation in the five wells (Ratawi-2, Ratawi-4, Ratawi-5, Ratawi-17, and Ratawi-19) in the Ratawi oilfield, southern Iraq. Open hole log analysis was utilized, and a series of calculations were applied to evaluate the reservoir properties, such as porosity, water saturation, and volume shale, that control the reservoir quality. The N-D cross plot diagram shows that limestone is the dominant lithology, and few shale contents is present in the upper and lower parts of the formation, while it is noticed that the volume of clay is constant throughout the formation in most of the wells, indicating that the formation is clean. Seven zones (A to G) have been identified and evaluated, depending mainly on full set logs to determine the most productive ones. Zones B, D, and F are classified as good reservoir zones with an average porosity of 21% and water saturation of 25%. A and C zones show reservoir and non-reservoir zones with porosity of 10% and water saturation of 40%. Finally, the remaining zones represented by E and G are classified as non-reservoir zones with a very low porosity of less than 4% and fully water-saturated.

Structural assessment and petrophysical evaluation of the pre-Cenomanian Nubian sandstone in the October Oil Field, central Gulf of Suez, Egypt

The low quality of the seismic resolution of the studied Cambrian Pre-Cenomanian formations, which rest directly on the basement in the October Field in the Gulf of Suez, requires study, and the structure pattern controlling these formations is uncertain. The poor quality of the seismic data resolution in the Gulf of Suez is due to the presence of thick sequences of evaporites represented by the South Gharib and Zeit formations. Therefore, the current study used seismic reflection data integrated with well-log data to define the structural-stratigraphic setting of the pre-Cretaceous Nubian reservoir sequence. The study aims at locating and delineating zones having excellent reservoir potential within the Nubian sequence horizons (Nubian Transition, main Nubian, Nubian marker-1, and Nubia marker-2, referred to as NT, MN, M1 and M2, respectively) through the integration of the 3D static modelling and the petrophysical parameters deduced from the well-log data processing. A detailed petrophysical analysis, based on the wireline logs of some wells, was performed to determine the lithological units using two types of cross plots (Neutron-Density and M-N plots), and the different petrophysical parameters that characterize the various Nubian horizons were also computed. 3D modelling was used to visualise the lateral and vertical changes of the reservoir characteristics. The seismic mapping reveals that the Nubian structure is controlled by an NW-SE trending (Clysmic trend) of an NE-plunging asymmetrical anticlinal feature unconformably resting on a basement horst. The main structure is affected by two major normal faults, which trend NW, andis cut by two smaller sub-parallel faults that disturb the core of the structure, which is unaffected by the easterly oriented faults of the Aqaba trend. The petrophysical analyses indicate that the Nubian sandstones have intervals of good reservoir quality, with a total net-pay thickness of about 500 m, net sand ratios (60–90 %), effective porosity (10–25 %), and hydrocarbon saturation (85%), which may encourage further drilling, especially in the southeast portion. The result of this study can be extended to the other Nubia sandstones resting on the basement complex in the Gulf of Suez.

Palaeozoic Amotape Group in the Colán District:

The Amotape Gr. Consists of metasedimentites with varying degrees of metamorphism and Paleozoic intrusions, exposed as isolated blocks that form an NNE-SSW belt, separating the Meso-Cenozoic depocenters of the Talara (west) and Sechura and Tumbes basins (east) along the Pacific margin of NW Perú. We describe three metamorphic/tectonic episodes that produced sub-planar structures (cleavages, fractures) affecting the rocks of the Amotape Gr, allowing this unit to be classified as a fractured reservoir. Field survey and multi-scale subsurface data from the Colán region, evidence a secondary porosity system associated with fracture networks that affect both the basin fill and the basement units. This configures a complementary unconventional exploration target. Sandstone levels in lateral contact with leptometamorphic rocks of the Amotape Gr. define good reservoir potential due to the preferentially brittle mechanical behavior of the basement, which develops abundant fractures. The porosity values of the Amotape Gr range between 4.62% and 1.23%, while permeabilities are on the order of 0.519-0.016 mD. Elevated trapping positions seem to be successfully sealed by Cretaceous units. The reservoir properties define a complementary play concept that could be extended to other positions of the technical basement in the Talara Basin and analogous regions.

Enhancing carbon sequestration efficiency and safety through albumin-optimized CO2 hydrate distribution and geological layer stability: An innovative approach

The persistently high global CO2 emissions are exacerbating the greenhouse effect issue. Scientists have explored methods such as carbon sequestration via subsea hydrate formation in response to global warming. However, this method faces a series of challenges when injecting CO2 on a large scale, including the slow formation rate of CO2 hydrates and potential leakage risks. Specially, the direct injection of promoters could lead to excessively high concentrations of additives close to the injection wells. This would consequently accelerate the local hydrate conversion, potentially causing reservoir blockage problems. The current study proposes a novel strategy involving additives that exhibit varying effects with concentrations. The high-concentration areas close to the wellbore can maintain the permeability by inhibiting hydrate formation; while the reduced concentration further away upon gas migration facilitates the rapid formation of CO2 hydrates. We successfully demonstrate the spatial and temporal differences in hydrate formation when using such additives. This can also facilitate the rapid formation of a dense hydrate cap layer over the reservoir, potentially preventing the leakage of CO2 gas. A new type of additive based on egg albumin was developed, which possesses the dual function and exhibits good biocompatibility and specific reservoir stability.