perISPGمجله زمین شناسی نفت ایران 2251-87382251-87382026-081529118articleHamed Amraeihamedamraei0@gmail.com1MSc in Petroleum Engineering, Sahand University of Technology<p>The identification of porosity types and structural geological studies of hydrocarbon reservoirs is one of the key petrophysical characteristics. To this end, in the first phase of the present study, the porosity types in the Ilam Formation, an oil well located in southwestern Iran, were determined from the constructed velocity deviation log using well logging data as a cost-effective alternative to identify porosity types; subsequently, thin sections were examined through petrographic analysis for verification. Petrographic examination of five available thin section samples from the studied well revealed that the microfacies of this formation contain intercrystalline, intergranular, and moldic porosities, with no evidence of fracturing in the reservoir. According to the velocity deviation log, the main reservoir zones of the Ilam Formation exhibit velocities close to zero, indicating the presence of intercrystalline and intergranular porosities with good permeability. Negative velocity deviations observed in this well indicate borehole breakouts, while zones with positive velocity deviations are associated with intragranular and moldic porosities, mostly present in non-reservoir intervals. Subsequently, in the second phase, structural geological interpretation of the reservoir was performed using the FMI imaging log. Accordingly, 69 bedding planes were interpreted in the studied reservoir, 9 of which with reliable dips with confident bedding contacts and 60 having dips with unreliable bedding boundaries. The average dip of the layers was determined approximately 4 degrees toward S30W, with a strike of N30W. Of the identified stylolites, 50 were of the bedding-parallel type, with an average dip of 4.5 degrees and a strike of N30W&ndash;S30W. Borehole breakouts occurred in the direction of the minimum horizontal stress acting on the borehole, with a strike of N20W&ndash;S20E, approximately corresponding to the general trend of the Zagros fold belt. Based on the analysis of conventional logs, velocity deviation, and FMI data, no natural or induced fractures were observed in the Ilam reservoir of the studied well. This study demonstrated that intercrystalline and intergranular porosities had the greatest influence on the reservoir quality of the Ilam Formation, whereas moldic porosity had a relatively minor effect.</p>http://journal.ispg.ir/Article/50496Velocity Deviation Log Thin Section Petrography FMI Log Structural Analysis of ReservoirperISPGمجله زمین شناسی نفت ایران 2251-87382251-87382026-0815291940articleSakineh Arefifardarefi.s@lu.ac.ir1Noshin Moradi Lirkashasinoshin.moradi.l@gmail.com2Thomas Algeoalgeot@ucmail.uc.edu3Jonathan Schuethjschueth@unomaha.edu4Lei Zhangzhanglei_cug@sina.com5Associate professor of Geology Department, Basic Sciences Faculty, Lorestan University, Khorramabad, IranGeology Department, Lorestan University, Khorramabad, Lorestan 68151-44316, IranDepartment of Geosciences, University of Cincinnati, Cincinnati, USADepartment of Geography/Geology, University of Nebraska Omaha, Omaha, USADepartment of Geosciences, China University of Geosciences, Wuhan, Chinana<p style="text-align: left;"><strong>In this study, the biostratigraphy of Upper Cretaceous deposits in the Pakal-e Garab section&mdash;with a thickness of 708 meters&mdash;located in the northeastern part of the Kabirkuh anticline, southwestern Iran, is investigated. This stratigraphic succession includes the Sarvak, Surgah, Ilam, and Gurpi formations, as well as the basal part of the Pabdeh Formation. To conduct a detailed biostratigraphic analysis and assess the diversity and distribution of planktonic foraminiferal fauna in the Upper Cretaceous deposits, the 708-meter-thick Pakal-e Garab section was studied. The investigation led to the identification of 24 genera and 75 species of planktonic foraminifera. Based on the recognized microfossils, 16 biozones and 2 sub-biozones were identified. According to these biozones, the age of the Sarvak Formation is assigned to the early Cenomanian to middle Turonian, the Surgah Formation to the Late mid Turonian to earliest Santonian, the Ilam Formation to the early Santonian to early&ndash;middle Campanian, and the Gurpi Formation to the middle Campanian to late Maastrichtian. At the base of the Pabdeh Formation, a 5-meter-thick purple shale containing diagnostic Paleocene fauna was identified, suggesting a Danian age for this part of the section. This study also presents evidence for the impact of the Oceanic Anoxic Event 2 (OAE2) at the Cenomanian&ndash;Turonian boundary and the end-Cretaceous mass extinction at the K/Pg boundary on the planktonic foraminiferal communities in the Pakal-e Garab section. These events are reflected in reduced diversity and significant changes in the faunal assemblages.</strong></p>http://journal.ispg.ir/Article/50998Upper Cretaceous biostratigraphy planktonic foraminifera Kabirkuh Anticline southeastern IlamperISPGمجله زمین شناسی نفت ایران 2251-87382251-87382026-0815294166articleZeinab Alizadehalizadeh786@gmail.com1Bahman Soleimanisoleimani_b@scu.ac.ir2Behzad Khanibehkhani@gmail.come3Department of Petroleum Geology and Sedimentary Basins, Shahid Chamran University of Ahvaz.Ahvaz, Iran.Professor in Department of Petroleum Geology and Sedimentary Basins, Shahid Chamran University of Ahvaz, Ahvaz, Iran.Technical Manager of Ariana Energy Company, Ahvaz<p>Surface geochemical studies are important tools in all stages of hydrocarbon potential exploration, from foreland basin identification to detailed exploration, and prospecting based on probable hydrocarbon flux, identification of sub-zones in mature fields, and monitoring of hydrocarbon drainage associated with production over time. In the current study, regional hydrocarbon potential prediction in northeastern Khuzestan (southeast of Dezful embeymant) was performed using soil gas analysis of collected samples (62 samples). Soil gas values ​​were measured using acid extraction (AE) methods, microbial investigation and gene extraction (MT1-MT2). Data analysis showed that the changes in MT2 analysis parameters along the sampling lines in the histogram plots show a positive skew due to the presence of surface geochemical anomalies and the presence of hydrocarbons in potential reservoirs. The ratios of ethane to methane, ethane to propane, and c1/c2+c3 to c2/c3+c4 indicate the type of hydrocarbon trapped in the subsurface reservoirs. Based on the obtained data, the samples of the study area are located in the range of oil reservoirs and in some cases oil reservoirs with gas. Hydrocarbon reservoirs based on the standard ratio c3/c1&times;1000, with a range of 20-200, show hydrocarbon accumulation with a majority of liquid hydrocarbons and in some cases with gas. Based on logc1/(c2+c3) versus logc2/(c3+c4), it also shows the dominance of liquid hydrocarbons and in less cases gaseous hydrocarbons with oil. The changes in the MT1 analysis parameter data along the sampling lines also indicate a good correspondence between the high anomaly of these parameters and the subsurface geological structural features (faults). The current results indicate that the samples are dominated by liquid hydrocarbons and in some cases with a gas cap. However, a few samples show hydrocarbon characteristics with heavy oil characteristics as well as surface contamination. In general, the results of all methods used in soil gas anomaly prediction showed good agreement with the structural elements of the area, so it can be considered a useful tool for identifying and monitoring hidden faults at the surface.</p>http://journal.ispg.ir/Article/51469Surface Geochemistry Microseepage Dezful Embayment Microbial Analysis Adsorbed Soil GasperISPGمجله زمین شناسی نفت ایران 2251-87382251-87382026-0815296779articleBabak Samanisamani.babak@gmail.com1Associate professor, Faculty of Earth science, Shahid Chamran University of Ahvaz, Ahvaz, Iran<p>In this study, gypsum veins occurring within the Gachsaran Formation of the Naft Sefid Anticline were employed as structural indicators to determine the orientation of the principal stress axes and to estimate the relative magnitudes of the principal stresses and pore pressure. For this purpose, Stereographic analysis of the veins pole data and Mohr diagram construction were performed. The results indicate that the wide dispersion of gypsum vein poles reflects the dominance of pore pressure over the mean stress (Pf &gt; &sigma;₂) during vein formation. Structural analysis revealed that the maximum principal stress axis (&sigma;₁) trends northwest&ndash;southeast, consistent with the general compressional regime of the Zagros fold-and-thrust belt. The calculated driving pressure ratio (R&prime;) ranges between 0.73 and 0.84, and pore pressure values vary from 4004 to 4571 units. The stress ratio (&Oslash; = 0.81) indicating three axial oblate shape of stress ellipsoid during the development of gypsum veins. These results highlight the significant influence of stress field orientation and fluid pressure on vein development within the Gachsaran Formation.</p>http://journal.ispg.ir/Article/51767Gypsum veins Pore pressure Stress field Naft Sefid Anticline Gachsaran Formation Zagros Fold-Thrust Belt perISPGمجله زمین شناسی نفت ایران 2251-87382251-87382026-0815298098articleMohammad Goodarzimohammadgoodarzi45@yahoo.com1Ph. D. student. Dept., of Geology, Faculty of science, Lorestan University, Khorramabad, Iran<p>The present study is being conducted in one of the wells of the Marun oil field to identify and distinguish sedimentary cycles using Cyclolog software and the relationship between sedimentary cycles and stratigraphic-biostratigraphic time boundaries in Upper Eocene (upper part of the Pabdeh Formation) and Oligo-Miocene deposits(Asmari formation). Initially, based on the study of microscopic thin sections, the ages of the Upper Eocene and Oligo-Miocene deposits were determined and separated, and then they were adapted to sedimentary cycles. The thickness of the studied area in this well is 446.5 meters and its dominant lithology is shale, calcareous shale, limestone, Sandstone and dolomite. Both the lower and upper boundaries (Pabdeh-Asmari and Asmari-Gachsaran formations) are continuous and gradual. After studying and examining the sedimentary cycles in the Cyclolog software, five negative boundary levels (NB) and four positive boundary levels (PB) were identified, and based on these boundary levels, four sedimentary cycles were identified and separated. NB1000 is in the Late Eocene time range, PB1000 corresponds to the Rupelian - Chattian time range, NB 2000 is in the Rupelian - Chattian time range, PB 2000 corresponds to the Chattian time range, NB 3000, in the Chattian time range, PB 3000 corresponds to the Aquitanian time range, NB 4000, in the Aquitanian time range, PB 4000 corresponds to the Aquitanian time range, and NB 5000 corresponds to the Aquitanian time range. After identifying the positive and negative boundary levels, it was determined that the first sedimentary cycle NB 1000 - PB 1000 was deposited in the Late Eocene- Rupelian - Chattian, the second sedimentary cycle NB 2000 - PB 2000 in the Rupelian - Chattian - Chattian, the third sedimentary cycle NB 3000 - PB 3000 in the Chattian - Aquitanian, and the fourth sedimentary cycle NB 4000 - PB 4000 in the Aquitanian area.</p>http://journal.ispg.ir/Article/52832Marun oil field Upper Eocene Oligo-Miocene Cyclolag sedimentary cyclesperISPGمجله زمین شناسی نفت ایران 2251-87382251-87382026-08152999122articleMohammad Goodarzimohammadgoodarzi45@yahoo.com1Mostafa Sedaqgatneiamostafasedaghat1364@gmail.com21 Ph. D. student. Dept., of Geology, Faculty of science, Lorestan University, Khorramabad, IranPh.D. Student, Sedimentology and Sedimentary Petrology, Bu-Ali Sina University, Hamadan, Iran.<p>In this study, diagenetic processes and paragenetic sequences of the Late Eocene&ndash;Oligocene deposits were investigated in a subsurface section of the Marun oil field. The thickness of the studied interval in this well is 272.5 m, and to examine its diagenetic processes, 150 microscopic thin sections were analyzed. The dominant lithology of the upper part of the Pabdeh Formation is mainly calcareous shale and shale, whereas the basal part of the Asmari Formation consists of limestone, calcareous marl, and, to a lesser extent, sandstone. The age of the upper part of the Pabdeh Formation in this well is Late Eocene, while the age of the lower part of the Asmari Formation in the studied well is Oligocene (Rupelian, Chattian&ndash;Chattian). Based on previous studies, the boundary between the Pabdeh and Asmari formations has been defined as conformable and gradual. According to previous petrographic studies, six microfacies related to basin, outer ramp, middle ramp (distal and proximal parts), and inner ramp (patch reef and open lagoon) environments were identified. Petrographic analyses revealed several diagenetic processes, including micritization; neomorphism (both constructive and destructive); cementation (equant, isopachous fibrous rim, drusy, and blocky calcite cements); mechanical and chemical compaction; dissolution and porosity development (fabric-selective and non-fabric-selective); and replacement (pyritization and silicification). Based on petrographic evidence, the paragenetic sequence of the Asmari Formation deposits in this field was interpreted to have occurred in four diagenetic environments: marine, meteoric, burial, and uplift-related. Three diagenetic stages&mdash;early (eogenesis), middle (mesogenesis), and late diagenesis (telogenesis)&mdash;were identified in the studied interval. Micritization and cementation, particularly in mud-supported facies, led to the occlusion of interparticle pores and a reduction of primary porosity. Overburden-induced compaction further reduced porosity and limited reservoir quality. In contrast, dissolution and the generation of secondary fractures enhanced secondary porosity in both grain-supported and mud-supported facies, thereby improving reservoir quality. Consequently, the reservoir quality of the Asmari Formation is heterogeneous and strongly controlled by facies type and the intensity of diagenetic processes.</p>http://journal.ispg.ir/Article/53116Marun Oil Field Pabdeh and Asmari Formations Diagenesis Paragenetic Sequence Reservoir Quality