جستجوی مقالات مرتبط با کلیدواژه "surmeh formation" در نشریات گروه "زمین شناسی"

Permeability is one of the important parameters in reservoir petrophysical studies, and evaluation of this parameter can be used as a key tool in the oil fields development. This study aim is permeability estimation and modeling of the Upper Surmeh Formation in one of the oil fields in the Persian Gulf. The Surmeh Formation with Jurassic age is considered as one of the most important oil and gas reservoirs in the Persian Gulf basin. In this study, we have used petrophysical well logs and 3D post-stack seismic data in the permeability evaluation process. The structural reservoir model has been prepared using the interpretation of seismic sections and well logs in the reservoir section. This model includes the interpretation of fault surfaces, geocell network and reservoir horizons. The geocell network used in this study used columns and geocells with dimensions of 50 * 50 meters in the X and Y directions. The thickness of the geocellular layers of each reservoir zone is designed to fit that zone in the reservoir section. The values permeability estimation was performed using the artificial neural network with a back-propagation algorithm. The results obtained from the artificial neural network were generalized in the studied reservoir well logs. The correlation coefficients value obtained from permeability estimation values with drilling core data is equal to 88%. Comparison of geostatistics results with permeability value shows that the proposed methods can provide acceptable results for reservoir permeability modeling.

The drilling fluid weight is determined according to the pressure and depth of drilling end stage fractures. The control of underground pressure of drilling fluid, as well as, transferring the solids and Cuttings of oil and gas wells are governed by drilling fluid weight. The drilling fluid weight causes to produce a pressure Equal to that of the formation and preventing the overflow of well and loss of drilling fluid. The accumulation of drilling solids and Cuttings in the fluid increase its weight resulting in slower drilling rate and decreasing the drilling bit life and undesirable fluid properties yielding mechanical and operational problems and hence more money and time consuming well driving process, while proper drilling fluid weight adjustment eliminate these problems. The combined physical and mass transfer methods results in better drilling fluid weight adjustment. In the present study the separation and improvement of drilling fluid weight in a 12 1/4" hole of a gas well in three stages was studied. First and second stage is related to change in mechanical separation and third step has been to using separators of mass transfer. In this formation, with enhancement of the fluid weight, the change in the screen (First stage) of the fluid weight at upper dolomite layer has been reduced and is kept at an optimal level. With the further enhancement of the fluid weight in the cherty zone layer, the change in screen rubber protector (second stage) caused the weight loss in this layer. Finally, the weight of the fluid is kept by centrifuge (third stage) in the mand member on 9.4 PPG proportional to the formation pressure. By continue drilling to neyriz and dashtak formations and require to higher drilling fluid weight (up to 11.5 PPG), adding weighting material is recommended.

  The Surmeh Formation, with the age of Late Jurassic, is one of the geographically widespread formations in the Zagros and Persian Gulf (Zigler, 2001), The major part of the Salman Oil Field, about two thirds, lies within Iranian waters, while one third is located in territorial waters of Abu Dhabi (Figure 1). As it is one of the most important oil reservoirs in the region, the Surmeh Formation contains gigantic oil reserves. The Surmeh Formation in the Salman Oil Field comprises mainly limestone and dolomite. It is equivalent to the Arab Formation of Saudi Arabia and other Arab countries (Al-Shahran & Narin, 2003). Surmeh Formation in Salman Oil Field is one of the most important oil tanks in the southeast of the Persian Gulf. The Salman oil field has different oil and gas reservoirs from different periods of Permian to Jurassic (James & Wynd, 1965). The main objective of this research is to identify sedimentary conditions and reservoir characteristics of Surmeh Formation. 223 thin sections (with a maximum distance of 30 cm) were prepared and most of them stained with Alizarin Red-S solution and ferricyanide potassium using the Dickson method (1965) in order to recognize calcite from dolomite. The carbonate microfacies were classified according to Dunham (1962) classification and a sedimentary model was proposed using Flugel (2010) scheme. The textures of dolomites were described following Sibley and Gregg (1987). Data gained from aforementioned sources were gathered in order to build and define facies, a depositional model, different diagenetic stages and reservoir quality. The present study is based on laboratory studies of microscopic thin sections
made from core samples. Results and This semi-circular shape of the Salman Oil Field structure reflects its origin as a salt dome.The ten identified microfacies include massive, nodular and laminated anhydrite with chicken-wire fabric, dolomudstone, mudstone with crystals and anhydrite nodules, wavy to laminated dolostromatolite boundstone, bioclast dolopackstone/dolowackestone, peloid-bioclastic dolopackstone/ dolowackestone, peloid-bioclastic dolograinstone, ooid-peloid dolograinstone, ooid dolograinstone, and bioclastic intraclast dolograinstone implying that the Surmeh Formation was deposited in four different environments from sabkha to marine shoal in a homoclinal carbonate ramp setting. The marine and meteoric diagenetic settings were susceptible to produce a variety of features from different types and phases of dolomitization, anhydritization, via cements from early marine to late diagentic cements to micritization, neomorphism, compaction and dissolution. Between all processes affected the Surmeh reservoir, dolomitization, in most cases, enhanced reservoir quality whereas anhydritization reduced reservoir quality.
Porosity variations along the Upper and Lower Arab units in Salman field is directly related to the amount of dolomitization. It also should be stated that, moderate to good reservoir quality is seen in facies belong to moderate to high energy zones of leeward to seaward shoal environments, whereas shallower facies of the inner ramp has the lowest amount of porosity and permeability. In these environments, pores have been filled with the secondary cements. The most important pore types are intergranular, intragranular, vuggy and moldic which are mostly seen in grain-dominated facies. Four types of dolomite in mud-dominated and two kinds of dolomite in grain-dominated textures have been recognized. Mud-dominated dolomites include dolomicrite, dolomicrosparite, dolosparite and scattered dolomites in a limestone matrix. Grain-dominated dolomites are known as fabric retentive and fabric destructive. Sabkha and seepage-reflux models are proposed for the formation of these dolomites. According to these models, it should be mentioned that the type 1 dolomites formed in sabkha environment, while types 2, 3 and 4 are formed under the influence of recrystallization of dolomicrites in a shallow burial environment. In addition, dolomitization in grain-dominated textures occurred from seepage-reflux processes in shoals adjacent to the limited and hypersaline lagoons. Acknowledgment
The authors are greatly acknowleged the Department of Geology, Islamic Azad University, North Tehran Branch and IOOC for providing all the data and logestic support for this study. We are also grateful to anonymous reviewers for their critical review and suggestions that improved our manuscript significantly. Keywords: Sedimentary environment; Diagenesis; Microfacies; Surmeh Formation; Salman Oil Field. References
Alsharhan, A.S., & Narin, A.E.M., 2003. Sedimentary basins and petroleum geology of the Middle East. Elsevier Science, Netherland, 843 p.
Dickson, J.A.D., 1965. A modified staining technique for carbonate in thin section. Nature, 205: 587.
Dunham, R.J., 1962. Classification of carbonate rocks according to depositional texture. American Association of Petroleum Geologists Memoir, 1: 108-121.
Flugel, E., 2010. Microfacies of Carbonate Rocks: Analysis, Interpretation and Application. Springer Verlag, New York, 996 p.
James, G.A., & Wynd J.G., 1965. Stratigraphic nomenclature of Iranian oil consortium agreement area. American Association of Petroleum Geologists Bulletin, 49 (12): 2182-2245.
Sibley, D.F., & Gregg, J.M., 1987. Classification of dolomite rock textures. Journal of Sedimentary Petrology, 57 (5): 967-975.
Zeigler, M.A., 2001. Late Permian to Holocene paleofacies evolution of the Arabian plate and its hydrocarbon occurrences. GeoArabia, 6(3): 445-504

The giant oil and gas fields in the northern Persian Gulf correspond to reservoir intervals which comprise Surmeh and Dalan formations. The main production units in these formations are their upper carbonates with typically ooid grainstone to dolostone lithofacies. As a comparative study the petrophysical characteristics of these formations were considered based on core logging, well logging and petrography of thin sections. The upper carbonate unit of the Surmeh Formation was studied in the Tabnak Field and the Dalan Formation in the South Pars Field. The average porosities were 17.15% and 8.50% for the Surmeh and Dalan reservoirs respectively. Their permeability’s were 308 md for the Surmeh and 30 md for the Dalan reservoirs. This contrast in porosity-permeability data of the studied reservoirs correspond to their depositional and diagenetic history. The high reservoir potential of the Surmeh Formation correspond to its interparticle primary porosity partly remained after partial early cementation and its intercrystalline porosity due to dolomitization. This is different in the Dalan Formation which had a different diagenetic history and its porosity mainly reduced during compactional processes during the burial as well as burial cementation. However, although the Surmeh reservoir has a higher porosity and permeability, it has a lower production yield, because of its limited source rock and migration pathways.

The Surmeh Formation comprises the Jurassic rocks of the Zagros Mountains and is considered as one of the most important petroleum reservoir units in the Persian Gulf basin. This formation is mainly composed of thick bedded and cliff forming carbonate rocks. The aims of this study are to investigate depositional history and sequence stratigraphy of the Surmeh Formation in the Fars province or eastern Zagros. Field and laboratory examination of the formation revealed the presence of 15 lithofacies related to different evolutionary stages of a carbonate platform. The results of different measured sections indicated that the lower part of the Surmeh Formation is composed of thick-bedded dolomitic facies containing Lithiotis fossils of Toarcian age related to a shallow marine epeiric platform. At the Aalenian tectonic movement along the preexisting basin faults resulted in the formation of adistally steepened ramp and Pars intrashelf basin. Consequently، alternating shale and limestone (calciturbidites) were deposited in the deep marine environment of an outer ramp during Bajocian. During Bathonian، overproduction of carbonates and progradation of platform facies over basinal deposits resulted in reestablishment of the homoclinal ramp that was in existence in the study area until the end of Jurassic. Vertical facies variations and comparison with global sea level curve revealed the existence of two second-order depositional sequences in the Surmeh Formation. The given sequences by themselves include 6 third-order sequences and correlate with lower Zuni I and lower Zuni II super sequences of Sloss (1963).

In this research, the Surmeh Formation of late Jurassic age in the southern zone of the Dezful embayment (Zagros basin in the SW of Iran) in Fahliyan anticline cross section were studied. A new method, in this discassion based on studies of fluid inclusion of oil in this Formation, in this discussion was presented. This research interpreted the data obtained from existing petroleum fluid inclusion in doubly polished thin sections from collected samples. These data includes temperature, salinity and reflected color of fluorescence radiation. Using this information, the characteristics of these section were evaluated and the depth of burial of host rock based on homogenizing temperature and salinity of fluid inclusion estimated 2040 m for the Fahliyan Formation. Using the fluorescent light reflection the API ranges 40 to 50 degrees and the density value obtained less than 0.74 gr/cm3, suggesting that the oil is ultra-light area.

In this research two stratigraphic sections of Lower Cretaceouse to Upper Jurassic sedimentary (Surmeh and Fahliyan Formation in Folded-Zagros Zone) have been selected. Based on microfacies studies (in 400 thin-sections) three species of Ichnofossils microcoprolites from Crustaceans related as the Follow: Palaxius decaochetarius، Helicerina siciliana، Palaxius tetraochetarius، palaxius isp. In general، considering Ichnotaxons studies، two assemblage-zones were identified for microcoprolites Crustaceans. Assemblage-zone (No: 1) of Tithonian to Berriasian and assemblage-zone (No: 2) which is lated of Valanginian، taxons Helicerina isp. Assemblage-zone (No: 2) which is related.

With respect to distribution of Surmeh Formation in Persian Gulf region, this formation may act as candidate source rock for hydrocarbon accumulation in this region. A comprehensive geochemical analysis including Rock-eval Pyrolysis, Gas Chromatography (GC), Gas Chromatography - Mass Spectrometry (GC-MS), were carried out on cuttings, in order to determine its hydrocarbon potentiality. Based on Rock-Eval data, the organic matter of the Surmeh formation is type II and III kerogen, with low maturity being at the end of diagensis stage. It exhibits a poor source rock characterization with low content of TOC. A close similarity can be seen, between organic matter extracted from Surmeh sample with that of oil sample collected from Upper Dariyan, Lower Dariyan and Maudud reservoir in the field. Biomarker results indicate that an open marine and few terrestrial input source rocks deposited in an anoxic condition with carbonate origin. Based on geochemical investigations Surmeh Formation isnt suitable source rock in the study area locally. Biomarker derived from rock extracts and trapped oils indicated that they share the same origin and were stained by laterally migrating oils from distant area.