Good Reservoir Quality Research Articles

Seismic stratigraphic units, paleogeography, and their effect on hydrocarbon distribution in the upper Neogene of the Pannonian Basin

The upper Neogene lacustrine sedimentary succession of the Pannonian Basin in Hungary was divided into 40 sequences (clinothems) by seismic stratigraphic methods. The geographic position of the clinothems reflects the gradual infilling of the basin. Different patterns of progradation, aggradation and retrogradation can be observed within the same clinothem sets along the northern shelf of Lake Pannon, demonstrating that lake level was controlled by local factors, such as tectonics and sediment supply, not solely by climate. The distribution of discovered hydrocarbon resources within the clinothems by time, by depositional environment, and by geographical regions was investigated for the first time through a systematic reservoir-level analysis. The reservoir sands are increasingly younger from the NW towards the SE, following the progradation of the shelf. Within each region, the oldest reservoir layers appear in the deep basin, whereas the second or third reservoir peaks are associated with deltaic environments. There appear to have been no general time intervals with basin-wide reservoir peaks when sands in anomalously large quantity or with specifically good reservoir quality were deposited. The petroleum accumulation was influenced by local factors in each subbasin, such as inherited structure, syn- and post-sedimentary deformation, sediment source and maturity, and topographic confinement.

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

AbstractThe 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.

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.

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.

Geophysical evaluation and petrophysical assessment of the Abu Roash "F" Member: A probable unconventional oil reservoir in Heba Field, eastern Abu Gharadig Basin, Egypt

This study investigates the geophysical properties of the Abu Roash F Member (AR/F) as a potential unconventional oil reservoir in Heba Field, located in the eastern region of the Abu Gharadig Basin (Egypt). Analysis of seismic data reveals the influence of Late Cretaceous dextral wrenching tectonic activity, evidenced by the presence of ENE-WSW anticlinal folds and intersecting NW-SE as well as WNW-ESE extensional faults throughout the study area. This tectonic regime is believed to have played a significant role in the formation of micro-fractures within the AR/F carbonate, which can enhance the reservoir's potential by improving its permeability and porosity. Petrophysical assessment identifies favorable reservoir zones within specific depth intervals across multiple wells. These zones exhibit promising reservoir quality, characterized by low shale volume (below 0.20), which indicates a cleaner reservoir rock with less clay content. Additionally, the high total porosity (ranging from 0.20 to 0.25) and moderate effective porosity (ranging from 0.15 to 0.20) suggest that a substantial portion of the rock's pore space is available for storing hydrocarbons. The low water saturation (between 0.40 and 0.50) further supports the presence of hydrocarbons, as it indicates that the pores are not predominantly filled with water. Furthermore, the high hydrocarbon saturation (ranging from 0.50 to 0.60) confirms the significant presence of hydrocarbons within the reservoir. The quantitative assessment of these petrophysical properties across all analyzed wells further confirms the good reservoir quality and potential of the AR/F Member. The integration of seismic and petrophysical data provides a comprehensive understanding of the reservoir characteristics, highlighting the AR/F Member as a significant oil reservoir in the eastern border of the Abu Gharadig Basin, particularly in Heba Field. This study's findings complement the existing knowledge of oil-bearing formations in the region, suggesting that the AR/F Member could be a valuable addition to the basin's hydrocarbon resources. The results underscore the importance of further exploration and development of the AR/F Member to fully realize its potential as a major contributor to the area's oil production.

Siliciclastic Reservoir Geo-modeling using TGS-SIS hybrid algorithm of the Upper Cibulakan Formation, Offshore Northwest Java Basin

Abstract The Upper Cibulakan is the primary hydrocarbon-producing formation in the Offshore Northwest Jawa area, operated by PHE ONWJ (Pertamina Hulu Energy Offshore Northwest Jawa). The productive interval in this formation comprises alternating sandstone and shale up to 45 feet of thick. Geologically, this interval is a shallow marine deposit with strong influence of tidal in the Ardjuna Sub-Basin, offshore part of Northwest Jawa Basin. The good quality reservoir layer is associated with Tidal Sand Ridges (TSR) facies characterized by lenticular sedimentary structures and the occurrence of shale intercalation in sandstone. The occurrence of shale, regarding its facies association package, varies greatly and significantly determines the quality of the reservoir. The geometry and quantity of facies distribution and association will significantly affect the calculation of hydrocarbon reserves during the modelling processes. Considering this, the selection of modeling methods and algorithms must be carried out appropriately. The use of the SIS (Sequential Indicator Simulation) algorithm in describing the TSR facies distribution still has shortcomings in randomness. Correspondingly, it requires to be combined with the TGS (Truncated Gaussian Simulation) method as it plays a great impact in calculating the distribution of sandstone and reservoir geometry. Meanwhile, SIS defines shale intercalation within TSR facies. Combining these two methods produces a more precise model of TSR facies associations. Besides, the concept of reservoir deposition is easier to explain based on the outcome result from the combined methods.

Pre-Jurassic weathering crust of the Kalinovoe hydrocarbon deposit, Tomsk region: composition and structure characteristics

Abstract. The study of pre-Jurassic deposits in the southwestern part of Western Siberia is highly relevant due to their potential of increasing hydrocarbon resources. These deposits are considered prospective targets for the discovery of hydrocarbon accumulations. Weathering crusts developed on the upper part of the Paleozoic rocks in the Tomsk region exhibit a complex composition and structure, reflecting the interplay of various factors, including primary sedimentary processes and later alteration processes, including fracture-controlled fluid flow and metasomatism. Aim. To establish the characteristics of the mineralogical composition and structure of the Paleozoic weathering crust formations developed at the Kalinovoe oil-gas-condensate field. Methods. Optical microscopy, X-ray diffraction, scanning electron microscopy. Results and conclusions. The composition and structure of the deposits at the boundary zone between the Paleozoic and Mesozoic successions have been studied in detail in the section of one of the wells at the Kalinovoe oil-gas-condensate field. The factual material is represented by core and thin sections of weathering crust deposits. The primary rock-forming minerals are silica minerals (quartz, chalcedony and opal) and clay minerals, with a lesser amount of carbonate minerals (siderite). Different lithological units were identified based on the content of minerals and bioclast (radiolarians and sponge spicules), indicating their formation under marine conditions. The protoliths of the altered rocks were carbonate-siliceous rocks, argillaceous limestones, and radiolarian cherts, which as a result of multiple stages of hydrothermal alteration and metasomatic processes were transformed into argillaceous-silicified rocks. In these rocks, with intense post-alteration overprinting, good reservoir quality porosity can develop. This porosity includes biogenic voids, microcavities, micropores, and open fractures.

Integrated petrophysical, sedimentological and well-log study of the Mangahewa Formation, Taranaki Basin, New Zealand

This study aims to address the problem of porosity preservation in the Mangahewa Formation of five main hydrocarbon fields covering onshore and offshore of the Taranaki Basin. An integrated reservoir characterization of the Middle to Late Eocene Mangahewa Formation is achieved through petrophysical evaluation, sedimentological and petrographical descriptions, and well log analysis methods. Petrophysical parameters (porosity and permeability) were acquired from the available core analysis and using mathematical equations to obtain other petrophysical matrices such as normalized porosity index (NPI) and reservoir quality index (RQI). Factors that affected Mangahewa reservoir were studied through thin-section microscopy and well-log analysis helped to measure the reservoir and hydrocarbon potentiality in the Mangahewa Formation. The Mangahewa Formation is dominated by sandstone and a range of marginal to shallow marine facies with varying hydraulic flow units (HFU). The Mangahewa Formation has a high positive correlation in porosity-permeability relationship and has a maximum of 4.67 μm RQI and 20.08 μm FZI (Well Kapuni-14) which reflect potential reservoir. The Mangahewa Formation observed from Wells Kapuni-14, Maui-A1G, McKee-16A, and Mokau-1 are dominated with 59.6%, 56.4%, 79.3%, and 68% of macro- and megapores, respectively. The presence of authigenic clay and calcite cement has greatly reduced the reservoir quality; however, primary and secondary pores are still observed within the Mangahewa sands. Moreover, well log analysis was carried out on four wells in Taranaki Basin, to run a qualitative and quantitative analysis of the Mangahewa reservoir. Eight potential reservoir zones were examined, revealing that the Mangahewa Formation has a very low shale volume of less than 6%, good effective porosity ranging between 11.0% and 13.3%, up to 36.2% of average water saturation and maximum of 69.8% average hydrocarbon saturation. In conclusion, from this comprehensive study, it can be deduced that the Mangahewa Formation possesses fair to good reservoir quality and hydrocarbon potentiality.

Reservoir characterization of the Abu Roash D Member through petrography and seismic interpretations in Southern Abu Gharadig Basin, Northern Western Desert, Egypt

This research combines petrography and seismic analysis to assess the Upper Cretaceous Abu Roash (AR)/D’s carbonate member composition in the Southwest Abu-Sennan oil field in the Southern Abu Gharadig Basin within the Northern Western Desert of Egypt. Various datasets were used, including petrographic thin sections, and electrical well logs for four stratigraphic wells (01, -02, -03, and, -04), along with a time domain seismic dataset covering the study area. Petrographic analysis across multiple depths and intervals has provided valuable insights. Well-01 demonstrates mud-wackstone with diverse mineral components at 1671–74 m MD, indicating favorable reservoir quality. Well-02 exhibits diverse compositions at intervals 1740–43 m MD and 1746–49 m MD, also showcasing good reservoir quality. Well-03 reveals a packstone rock type at 1662–65 m MD with favorable reservoir characteristics. Well-04 displays peloids Wack-Packstone and Oolitic Packstone at intervals 1764–67 m MD and 1770–73 m MD, respectively, both indicating good reservoir quality. Integrating the petrography and seismic attributes results concerning the structural level of AR/D concerning the used wells, it's evident that Well-03 stands out due to its relatively high structural level, drilled near a major fault, revealing distinct fracture sets that contribute to a notably high reservoir quality as depicted in the RMS amplitude and Ant track attributes maps. AR/D reservoir levels in wells 02, and, 04, are relatively positioned at structurally lower levels, and face challenges with overburden pressure and mechanical compaction, resulting in diminished facies quality for the reservoir. Seismic attributes like the Ant track and RMS amplitude indicated that the presence of fractures within the AR/D Member's carbonate is linked to the prevalence of interpreted normal faults. The implemented procedure in this research can be applied to enhance comprehension of AR/D carbonate reservoirs in adjacent regions, thereby increasing the hydrocarbon exploration possibilities.

Coupling of source rock gas expulsion intensity and reservoir quality in time and space-a key to determine gas accumulation in Upper Paleozoic tight sandstones of the Mugua gas field, Ordos Basin, China

Research on gas accumulation mechanisms and variations in gas saturation is limited in the newly established Mugua gas field in the Ordos Basin. Understanding these aspects is vital for reduce drilling uncertainty and exploration risk. This study employed a variety of methods, including: (1) the use of organic geochemical examinations to determine the gas expulsion intensity of hydrocarbon source rocks; (2) fluid inclusion analyses to determine the time of gas accumulation; (3) a combination of optical microscopy, scanning electron microscopy observations, pore-simulation and permeability tests, mercury-intrusion capillary pressure experiments, and nuclear magnetic resonance studies to assess the properties of the reservoir quality and identify the tight sandstone rock type; (4) wireline logging and interpretive data analyses to research the gas saturations features; and (5) establish reservoir quality evolution model to systematically study this problem. Integrating fluid inclusion homogenization temperatures with burial and thermal histories indicates that gas accumulation in the Mugua gas fields occurred throughout the Early Jurassic to Late Cretaceous period. Five diagenetic facies have been identified: dissolution, quartz-cemented, clay mineral filling, tightly compacted, and carbonate-cemented facies. The reservoir quality evolution model reveals that the five diagenetic facies experienced densification before the period of gas accumulation. Therefore, for gas accumulation in tight sandstones, it is essential that mature and gas-generating source rocks, provide sufficient expulsion forces to drive gas into the rocks. The mechanism of gas accumulation in the Mugua gas field's tight gas sandstone reservoirs involves the process occurring in sandstones that are either near or interbedded with source rocks, under high pore-fluid pressure generated by gas production. Compared to other Upper Paleozoic gas fields in the Ordos Basin, the gas expulsion intensity in the Mugua gas field is lower, ranging from 6.12–8.39 × 108 m3/km2. Due to the low gas expulsion intensity, the Shihezi 8 Member's tight sandstone reservoirs, situated away from the source rock, typically show low gas saturation. Conversely, the dissolution and quartz-cemented facies within the Benxi, Taiyuan, and Shanxi Formations, intimately interbedded with hydrocarbon source rocks, exhibit good reservoir quality. They offer ideal conditions for gas accumulation, making them prime candidates for exploration and development.

Reservoir Prediction and Prospectivity of Omos Field Onshore Niger Delta Basin, Nigeria

Reservoir prediction and prospectivity are performance indices of the oil and gas field development planning and reserves estimation which depicts the behaviour of the reservoir in the future; its success is dependent on accurate description of the reservoir rock properties, fluid properties, rock-fluid properties and flow. Hence, the objective of this paper was to investigate and predict the reservoir and prospectivity of Omos Field, Onshore Niger Delta Basin, by integrating appropriate standard methods. Results obtained from rock physics attribute map analysis revealed very high Mu-Rho values between 13.0-16.2 Gpa, that is expected for sand presence, and this agrees with the good quality reservoir sands predicted from sequence stratigraphy study.Lambda-Rho values obtained ranges between - 1 to 9.5 GPa, with a much lower value between -1 to 4.3 in the prospective zone that indicates the presence of hydrocarbon bearing sand. These results agree with the results of structural and amplitude maps analysis. Hence the prospective reservoir has a very good hydrocarbon potential in this zone and should be a target for further appraisal for development and production purposes.

Petrographical and petrophysical rock typing for flow unit identification and permeability prediction in lower cretaceous reservoir AEB_IIIG, Western Desert, Egypt

The primary objective of this study is to identify and analyze the petrophysical properties of the newly investigated AEB_IIIG member reservoir in Meleiha West Deep (MWD) Field and to classify it into different rock types. Additionally, this research intends to develop mathematical equations that may be utilized to estimate permeability in uncored sections of the same well or in other wells where core samples are unavailable. The analysis focused on the pore hole records of ten wells that were drilled in MWD Field. The reservoir levels were identified, and their petrophysical parameters were evaluated using well logs and core data. We were able to recognize seven different types of rocks (petrophysical static rock type 1 (PSRT1) to PSRT7) using petrography data, the reservoir quality index (RQI), the flow zone index (FZI), R35, hydraulic flow units (HFUs), and stratigraphy modified Lorenz (SML) plots. The analysis of the petrophysical data shows that AEB_IIIG has unsteady net pay thicknesses over the area. It has a range of 8–25% shale volume, 12–17% effective porosity, and 72–92% hydrocarbon saturation. The RQI results show that psrt1, psrt2 and psrt3 have a good reservoir quality as indicated by high R35 and helium porosity, respectively. They contribute with more than 75% of the reservoir production. The equation derived for each rock type of AEB_IIIG reservoir can be employed to forecast the permeability value distribution inside the reservoir.

Structural and Stratigraphic Reservoir Characterization of “MONI” Field¸ Niger Delta.

Reservoir characterization of “MONI” field of the Niger Delta has been carried out using well log and seismic data. The study is aimed at delineating structural and stratigraphic features associated with hydrocarbon entrapment of the field. Lithostratigraphic correlation reviewed two main lithologies which are reservoir sands and seal shales. Well log correlation and interpretation across the field indicates – main stratigraphic bounding surface which include two sequence boundaries and one maximum flooding surface. This indicates about three depositional sequences exists in the study area. Stacking patterns (progradation, retrogradation, and aggradation) were delineated and interpreted as lowstand system tract (LST), highst and system tract (HST), and transgressive system tract (TST). The alternation of LST, HST and TST offers good reservoir and seal for the hydrocarbon accumulation. The depositional environment of the reservoirs ranges from subaerial channel deposits, barrier bar, tidal channel sands to delta distributary channel fill. Subaerial channel deposits have a bad reservoir quality, tidal channel sands possess a fair reservoir quality while delta distributary channel fill have a good reservoir quality. Petrophysical analysis shows that three reservoirs delineated have a porosity ranging from 19.37% to 23.62%, permeability ranging from 1408.71 to 1855.36 mD, a Net-to-Gross ranging from 0.46 to 0.88, volume of shale ranging from 11.72% to 24.92%, Water saturation ranging from 37.24% to 47.96% and hydrocarbon saturation ranging from 52.04% to 62.76%. Structural interpretation reviewed four main faults that serves as traps to the accumulation of hydrocarbon. Three hydrocarbon bearing sands were interpreted in the seismic volume. Time and depth structure maps show that the hydrocarbon bearing structure is a fault assisted anticlinal structure. Seismic facies analysis reviewed five facies. The study concluded that structural and stratigraphic features can be used to characterize reservoirs.

Estimation of the Petrophysical Properties of the Lower Cretaceous Yamama (YC) Formation in Siba Field

In southern Iraq, the Yamama Formation has been a primary carbonate resource since the Lower Cretaceous era. This study covers Siba Field, which is located in southeastern Iraq. This paper will be devoted to a YC unit of study. The most crucial step in reservoir management is petrophysical characterization. The primary goal of this research is to assess the reservoir features and lithology of the Yamama (YC) Formation in the Siba region. Accessible excellent logs include sonic, density, neutron, gamma-ray, SP, and resistivity readings. The Interactive Petrophysics (IP4.4) program examined and estimated petrophysical features such as clay volume, porosity, and water saturation. The optimum approach was the neutron density and clay volume calculation using the Gamma Ray Method (VclGR), it was 0.246 in SB-6 since they are not impacted by anything. The Archie method was chosen due to its suitability for limestone. The lithology and mineralogy of the formations were determined using M-N cross plots; the diagram revealed that the Formation was composed of limestone. The Archie parameter was determined using the Pickett plot and formation water resistivity from the Pickett plot and SP log where the results were similar in all wells (RW=0.016, m=2.08, n=2.3, a=1.1). In addition, the higher section of the formation has good reservoir qualities such as density is (2.368g/cc), porosity is (PHIE=0.117) in SB-6.

Sedimentary facies controls on reservoir quality of the Abu Madi Formation, offshore Nile Delta Basin, Egypt

The present study investigates the sedimentological analysis and petrophysical properties of the Messinian Abu Madi reservoir (AMR), offshore Nile Delta Basin in order to determine how facies heterogeneities control reservoir quality. This approach was performed by integrating core data from Mina-1 well and BE-1 well and wireline logs from four wells (BN-1, BN-2, BE-3 and Mina-1). Based on core studies, seven clastic facies have been identified, of which five form sandstone reservoirs. These facies have accumulated within a deep incised canyon-fill during four successive fluvial sub-environments; braided fluvial channel, point bar, floodplain, and abandoned channel. These fluvial sediments were changed into tidally influenced fluvial/estuarine deposits with aggradational-retrogradational stacking patterns due to a transgressive event during the Messinian time. Based on the well log petrophysical evaluation, the Abu Madi reservoir has a total porosity of 0.20–0.26 v/v and effective porosity in the 0.18–0.25 v/v range. Shale volume ranges from 0.04 to 0.09 v/v, and water saturation ranges between 0.15 and 0.45 v/v. Four reservoir rock types were recognized and interpreted as a function of composition and therefore having different petrophysical characteristics. RRT1 and RRT2 show good petrophysical properties and good reservoir quality. The best reservoir quality occurs in massive sandstones (RRT3), which have porosities up to 26% and permeabilities up to 1440 mD. RRT4 has a poor reservoir quality with porosity of 5.4% and permeability of 0.6 mD. The reservoir porosity heterogeneities and reservoir quality have been strongly impacted by the original composition and primary depositional facies.

Structural and petrophysical characteristics of the Turonian “AR/G″ reservoirs in heba field (Western Desert, Egypt): Integrated approach for hydrocarbon exploration and development

The evaluation of the Turonian “AR/G″ reservoirs in the Heba field, located in the eastern part of the Abu Gharadig Basin in the Western Desert of Egypt, is a crucial aspect of hydrocarbon exploration and development in the region. To achieve this, a comprehensive analysis of wells and seismic data was conducted. The seismic interpretation revealed that the Upper Cretaceous dextral wrenching tectonic has influenced the Heba field and extends throughout the northern Western Desert. Through the integration of seismic attributes, such as RMS and Sweetness, and well log correlation during the mapping phase, an ENE-WSW faulted anticline structure was identified in the study area. This geological feature was found to be plunging towards the NW direction and stretches throughout the study area, although it is fragmented by several NW-SE and WNW-ESE normal faults with lengths ranging from 1 to 10 km. The well log analysis of the AR/G Member has identified two proposed oil zones (Zone 1 and Zone 2), both exhibiting good reservoir quality across all examined wells. These oil zones are characterized by low to moderate shale volume (15%–40%), high total porosity (20%–28%), moderate effective porosity (15%–17%), moderate water saturation (40%–67%), and low bulk volume of water (6%–9%). These findings suggest that the AR/G Member has the potential to be a productive hydrocarbon reservoir. Integrating the structural and petrophysical characteristics of the “AR/G″ reservoirs can greatly assist in identifying suitable locations for oil exploration and development in the study area. This integrated approach enhances the ability to predict the behavior and production potential of the “AR/G″ reservoirs in the Heba field (Western Desert, Egypt).

Lithofacies, Depofacies and Reservoir Characteristics of Well TMG-08, Opolo Field, Niger Delta

Sediments within the depth intervals of 2834-6620.9 ft in Well TMG-08 of Opolo Field, Niger Delta, were investigated with the aim of establishing its lithofacies, depositional environments and petrophysical characteristics using a suite of Well-Logs. The Shale lithology is more dominant and of thicker units than the sand at the upper section of the log which could be interpreted as sediments of the Akata Formation. Five sand bodies were identified within the study interval. The shapes of the gamma ray signatures were funnel, cylindrical and symmetrical. Prograding, aggradational and combined prograding and retrograding parasequences were identified from the stacking patterns of the gamma ray curves. The environments of deposition delineated were Transgressive shelf sands and mixed Tidal flat environment, Crevasse splay, River mouth bar, Delta front shoreface, and Fluvial channels, Tidal sands, Prograding delta distributaries. The predicted porosity and permeability show moderate to good quality reservoirs. The average porosity value (0.13 *100= 13% Ranging from Poor to moderate), with a moderate permeability Value (16.87mD) due to the presence of high volume of shale in the reservoirs. The thicknesses of the reservoir are small averaging 5.5ft (16.92m). The depositional environment shows that sand B and C are continuous within the reservoir. The environment of deposition of the study area lies within the marginal marine

Reservoir quality of the Late Cretaceous Volador Formation of the Latrobe group, Gippsland Basin, Australia: Implications from integrated analytical techniques

Increasing demand for energy due to the populous Eastern Australia has driven oil and gas industries to find new sources of hydrocarbons as they are the primary energy suppliers. Intensive study has been done on the Volador Formation in the Gippsland Basin by means of core-based petrophysical, sedimentological, and petrographic analyses as well as well log-based interpretation and capillary pressure test. Five wells from Kipper, Basker and Tuna fields with available dataset were investigated in this study: Kipper-1, Basker-1, Basker-2, Basker-5 and Tuna-4. Overall, the formation has good reservoir quality based on the high porosity and permeability values obtained through core and well log petrophysical analyses. The formation made up of mostly moderate to coarse quartz grains that has experienced strong anti-compaction and is poorly cemented. Montmorillonite and illite clays are seen dispersed in the rock formation, with the minority being mixed clays. These clays and diagenetic features including kaolinite cement and quartz overgrowth that can lead to porosity reduction only have insignificant impact on the overall reservoir quality. In addition, capillary pressure data shows that most samples are found in the transition to good reservoir zones (<50% saturation). The results obtained from this study have shown that the Volador Formation in the Gippsland Basin is worth for hydrocarbon exploration.

Reservoir quality evaluation of the Narimba Formation in Bass Basin, Australia: Implications from petrophysical analysis, sedimentological features, capillary pressure and wetting fluid saturation

The evaluation of reservoir quality was accomplished on the Late Paleocene to Early Eocene Narimba Formation in Bass Basin, Australia. This study involved combination methods such as petrophysical analysis, petrography and sedimentological studies, reservoir quality and fluid flow units from derivative parameters, and capillary pressure and wetting fluid saturation relationship.Textural and diagenetic features are affecting the reservoir quality. Cementation, compaction, and presence of clay minerals such as kaolinite are found to reduce the quality while dissolution and secondary porosity are noticed to improve it. It is believed that the Narimba Formation is a potential reservoir with a wide range of porosity and permeability. Porosity ranges from 3.1% to 25.4% with a mean of 15.84%, while permeability ranges between 0.01 mD and 510 mD, with a mean of 31.05 mD. Based on the heterogenous lithology, the formation has been categorized into five groups based on permeability variations. Group I showed an excellent to good quality reservoir with coarse grains. The impacts of both textural and diagenetic features improve the reservoir and producing higher reservoir quality index (RQI) and flow zone indicators (FZI) as well as mostly mega pores. The non-wetting fluid migration has the higher possibility to flow in the formation while displacement pressure recorded as zero. Group II showed a fair quality reservoir with lower petrophysical properties in macro pores. The irreducible water saturation is increasing while the textural and digenetic properties are still enhancing the reservoir quality. Group III reflects lower quality reservoir with mostly macro pores and higher displacement pressure. It may indicate smaller grain size and increasing amount of cement and clay minerals. Group IV, and V are interpreted as a poor-quality reservoir that has lower RQI and FZI. The textural and digenetic features are negatively affecting the reservoir and are leading to smaller pore size and pore throat radii (r35) values to be within the range of macro, meso-, micro-, and nano pores. The capillary displacement pressure curves of the three groups show increases reaching the maximum value of 400 psia in group V. Agreement with the classification of permeability, r35 values, and pore type can be used in identifying the quality of reservoir.

Integrated Core and Log Data to Determine the Reservoir Flow Unit and Rock Facies for Mishrif Formation in South Eastern Iraq

This work represents study the rock facies and flow unit classification for the Mishrif carbonate reservoir in Buzurgan oil Field, which located n the south eastern Iraq, using wire line logs, core samples and petrophysical data (log porosity and core permeability). Hydraulic flow units were identified using flow zone indicator approach and assessed within each rock type to reach better understanding of the controlling role of pore types and geometry in reservoir quality variations. Additionally, distribution of sedimentary facies and Rock Fabric Number along with porosity and permeability was analyzed in three wells (BU-1, BU-2, and BU-3). The interactive Petrophysics - IP software is used to assess the rock fabric number, flow zones, and reservoir quality index. The Mishrif Formation has four distinct rock types and groups that have been recognized using the approach. The first rock type represents a poor reservoir quality (mud-dominated fabrics) with rock-fabric numbers equals to 2.5-4, the second rock type reveals a moderate reservoir quality (wackestone-Packstone Microfacies), the third rock type depicts a good reservoir quality (grain-dominated packstone) with rock-fabric numbers equals to 1.5-2.5 and 0.5-1.5.