Petroleum geology
Haniyeh Ghayeni; Mohamad Hosein Mahmudy-Gharaie
Abstract
Investigating the hydrocarbon generation potential of the Kazhdumi Formation, as the most important oil source rock in the Zagros sedimentary basin, is of great importance. The expansion of the Kazhdumi Formation in the Zagros Basin has been associated with differences in sedimentation depth of the basin ...
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Investigating the hydrocarbon generation potential of the Kazhdumi Formation, as the most important oil source rock in the Zagros sedimentary basin, is of great importance. The expansion of the Kazhdumi Formation in the Zagros Basin has been associated with differences in sedimentation depth of the basin leading to varieties in sedimentary facies and the organic matter preservations. Five black shale samples from Perchestan and Tang-E Maghar sections were selected for analysis by Rock-Eval pyrolysis, and were compared to the data of 25 Kazhdumi samples from different oil fields of Nowrouz, Soroush, Azadegan and Chah-E Binak, previously studied in the Zagros Basin. Additionally, sedimentary environment and depositional conditions were investigated. Sedimentary and geochemical evidences indicate a dominant condition of high organic content shale deposition in the reducing to semi-oxidative environments. The values obtained for total organic carbon (TOC) ranged from 1.2 to 6.9%. Examination of the thermal maturity of the samples showed a wide range from the immature range to the middle oil window, which are often in the range of type II and III kerogens. Finally, the drawing of the TOC vs. S2 diagram represents the higher hydrocarbon generation potential of the Kazhdumi Formation in the Tang-E Magher section, and the TOC vs. HI diagram shows the greater oil generation in the Soroush field, compared to the other studied areas.
Petroleum geology
Shadi Mohavel; Golnaz Jozanikohan; Sohaila Aslani
Abstract
The presence of clay minerals of any type, amount or distribution pattern in hydrocarbon wells causes numerous problems in the formation evaluation. In this research, 15 core samples from Asmari Formation in the Maroun Oilfield were selected in order to study the type and distribution pattern of clay ...
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The presence of clay minerals of any type, amount or distribution pattern in hydrocarbon wells causes numerous problems in the formation evaluation. In this research, 15 core samples from Asmari Formation in the Maroun Oilfield were selected in order to study the type and distribution pattern of clay minerals by laboratory investigations. The XRD and microscopic results showed the studied samples consisted mainly of quartz (14.7-72.2%) and carbonate minerals (3.0-65.4%) as main constituent phases; while the plagioclase (0.0-6.7%) and clay minerals (3.3–44.5%) were identified as the main accessory minerals. In some samples, sulfide and ferrous minerals (0.0-2%) were also identified. The calculated percentage of illite in mixed-layer smectite/illite showed the diagenesis has occurred at different depths of reservoir. The SEM/EDX analysis performed on various types of clay minerals showed that kaolinite size varied from 0.7 to 6.5 μm in studied samples. In addition, Illite size ranged in our studied samples from 0.4 to 3.6 μm. Our results indicate that the clays in the Asmari Formation occur in three main patterns as dispersed, pore-bridging and pore-filling with the variation of the total amount of clay minerals, min 3.3% and max 44.5% across the length of Asmari Formation.
Petroleum geology
Nasim Maleki Sadeghi; Ahmad Ahmadi-khalaji; Reza Zarei Sahamieh; Zahra Tahmasbi
Abstract
The study area is a part of Zagros Folded zone and located in the Lorestan sedimentary basin. In this regard, three areas with high bitumen potential were selected, which include the northern area of Kuhdasht, northeast of Poldokhtar and southeast of Sepiddasht. In the study areas, bitumens are exposed ...
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The study area is a part of Zagros Folded zone and located in the Lorestan sedimentary basin. In this regard, three areas with high bitumen potential were selected, which include the northern area of Kuhdasht, northeast of Poldokhtar and southeast of Sepiddasht. In the study areas, bitumens are exposed as veins between the fractures and as interlayers with host rock that the thickness of these veins is between 10 cm to more than 1.5 meters. Field studies showed that the studied bitumens have developed in the shales of Amiran Formation. Based on the results of organic geochemistry, 80.10 to 93.60% of the extractable saturated compounds are in the category of asphalts and have a very good quality in terms of thermal maturity (maturity of organic matter). The studied samples are formed in a reducing to slightly reducing sedimentary environment. Drawing the diagram of C34/C35 Homohopane vs. C29/C30 Hopane for the studied bitumens showed that the generating rocks of the studied samples are carbonate and detrital in nature. This can be explained by the lithology of bituminous formations such as Ilam and Gurpi formations in the study areas. The triangular diagram of regular streams (m/z = 217) for the studied bitumens showed that the source of organic compounds of the studied bitumens is mostly marine with a small amount of entry from dry environments. Severe depletion of the carbon isotope (average -28.83 per mill) indicates organic origin and biomass in these samples. On the other hand, sulfur compounds with depletion (-12.16 per mill) indicate formation in a reduced to semi-regenerated sedimentary environment and oxygen isotope data (+15.03 per mill) indicate the formation of organic matter of sedimentary origin.
Petroleum geology
Mohammad Sadeghi; Morteza Tabaei; Behnam Rasekh; Mohammad Reza Kamali
Abstract
The purpose of this research is to identify the source of hydrogen sulfide gas using microbiological, geochemical studies on samples of output, input sea water, and injection water to Sivand (SIC C), Dana (SIC D), and Esfand (SIC E) located in the operational area of Siri Island. Therefore, in order ...
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The purpose of this research is to identify the source of hydrogen sulfide gas using microbiological, geochemical studies on samples of output, input sea water, and injection water to Sivand (SIC C), Dana (SIC D), and Esfand (SIC E) located in the operational area of Siri Island. Therefore, in order to find out the origin of the reservoir souring of the oil fields of Siri Island, after the initial and library studies, as well as the reservoir characteristics, the history of injection and production of the fields, the most probable hypothesis of the reservoir souring in these fields can be caused by the processes of bacterial sulfate reduction (BSR). Therefore, the culture media required for the growth of sulfate-reducing bacteria was prepared to prove the hypothesis. After field sampling, some microbiology tests were performed on the samples. Since, in initial observations of the sampling, the change in the color of the samples from pink to black indicated that the samples contained sulfate-reducing bacteria. For this purpose, DNA extraction was carried out on the infected samples. In the complementary stage, the samples entered the molecular identification phase. The output of the results was that the bacteria with the highest frequency (about 81%) are Desulfovibrio bacteria, which can consume hydrogen in the oil reservoir and turn them into hydrogen sulfide gas. Therefore, the primary hypothesis of the research is proven. That is the main cause of reservoir souring of the oil fields in Siri Island, the processes related to SRB in which Desulfovibrio bacteria plays a significant role.
Petroleum geology
Mohammad Javad yousefzadeh; Bijan Maleki; Mir Hassan Moosavi; parviz armani
Abstract
Investigation of probable source rocks in oil fields is very important. In this study, in addition to evaluating the hydrocarbon potential, the kinetic models of Lopatin and Arrhenius were used to more precisely assess the source rock maturity status as well as the percentage of oil generation in the ...
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Investigation of probable source rocks in oil fields is very important. In this study, in addition to evaluating the hydrocarbon potential, the kinetic models of Lopatin and Arrhenius were used to more precisely assess the source rock maturity status as well as the percentage of oil generation in the Solabdar oil field. This field is southeast of Bibi Hakima Square, located in the Dezful embayment. Possible source rocks are scorpions, scorpions, Gurpi and Pabdeh. The samples were also analyzed kinetically and the transformation ratio (TR) of kerogen to the generated hydrocarbon was determined. According to the burial history, the source rock of Kazhdomi formation has reached the highest temperature and depth compared to other source rocks. According to the results of Lopatin method, the transformation rate of organic matter in formations, Gurpi and Pabdeh was determined by 41%, 30% and 30%, respectively. This transformation rate by Arrhenius method was 47%, 15%, and 13%, respectively. This difference is due to the two-factor assumptions that the article discusses.
Petroleum geology
Majid Safaei Farouji; Hosein Rahimpour- bonab; Mohammadreza Kamali; Buyuk Ghorbani
Abstract
Geochemical investigation of Kazhdumi and Pabdeh formations suggest a shaly and carbonate lithology as well as a suboxic-anoxic marine depositional environment for both formations. On the other hand, the thermal maturity of the Kazhdumi Formation is equivalent to the mid of oil window while thermal maturity-related ...
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Geochemical investigation of Kazhdumi and Pabdeh formations suggest a shaly and carbonate lithology as well as a suboxic-anoxic marine depositional environment for both formations. On the other hand, the thermal maturity of the Kazhdumi Formation is equivalent to the mid of oil window while thermal maturity-related parameters show that the Pabdeh Formation has not entered the oil window. Biomarkers are indicative of derivation of the four oil samples from a carbonate-shaly or marly source rock. Also, thermal maturity-related biomarkers reflect a peak mature stage for all of the four samples. Different values of oleanane index in oil samples is implying a more significant role of the Pabdeh Formation in hydrocarbon embedded in 36, 56, 55 wells in compare to well number 22. In general, oil-source correlation introduces both Kazhdumi and Pabdeh formations as source rocks for the crude oils.
Petroleum geology
kambiz Mehdizadeh farsad; davood Jahani; alireza hajian; Fereidoun Rezaei
Abstract
Hydraulic fracture is known as one of the effective methods for producing or being caused a change in the physical structure of a reservoir rock. In oil and gas reservoirs which have been fractured by a hydraulic approach, this method causes that a production well and the time of reservoir production ...
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Hydraulic fracture is known as one of the effective methods for producing or being caused a change in the physical structure of a reservoir rock. In oil and gas reservoirs which have been fractured by a hydraulic approach, this method causes that a production well and the time of reservoir production increase. In this research, fracture analysis have been comprised with the outputs produced by previous models. Its results show that the opening intersection produced by hydraulic fracture has been being changed in various time during pumpage, therefore, the fracture should be kept open by propanent substances. In the next stage, the amount of porosity pressure in the trend of the fracture is considered. In this survey, two parameters, i.e. the fracture measure and the change of pore pressure have been obtained using the hydraulic fracture modeled process under the actual condition of pay zone and its confining layers, and by the finite element approach. In this method, pumping processing has been assigned for fluid and propanent. At the end, by making a comparison between these result and the results obtained from previous studies, it can be found out that this approach is applicable and efficient.
Petroleum geology
Seyed Mahmoud Fatemi Aghda; Mashaallah Taslimi; Ahmad Fahimifar
Abstract
The main aim of this study is to examine the feasibility of estimation of flow zone indicator in carbonate rocks by integration of hydraulic flow unit concept a nuclear magnetic resonance technology. The two main permeability models Timur-Cotes and mean T2 models, because of worldwide usage of these ...
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The main aim of this study is to examine the feasibility of estimation of flow zone indicator in carbonate rocks by integration of hydraulic flow unit concept a nuclear magnetic resonance technology. The two main permeability models Timur-Cotes and mean T2 models, because of worldwide usage of these models, were used for evaluating the ability of nuclear magnetic resonance to estimate the flow zone indicator. One of the most important points in this study is the use of the experimental results of the nuclear magnetic resonance in laboratory on core that is never done in Iran. In this study, 24 carbonate samples were selected, and porosity, permeability and nuclear magnetic resonance experiments were performed. Then, using the results of the porosity and permeability tests, the flow zone indicator was determined and was considered as an index for evaluating the accuracy of the nuclear magnetic resonance method. Using the parameters obtained from the nuclear magnetic resonance test and nuclear magnetic resonance permeability models, flow zone indicator was estimated and compared with the core flow zone indicator. According to the results, it seems that the nuclear magnetic resonance permeability models, with the routine coefficients, do not have the proper ability to estimate the flow zone indicator, and it is necessary to correct the coefficients according to the lithology of rocks.
Petroleum geology
ayeshah salmani; Hossain Rahimpour-Bonab; Mohsen Ranjbaran; Seyed Mohsen Aleali
Abstract
Asmari Formation (Oligocene - Miocene) is the first fractured proliferous carbonate reservoir that ever known in the world and is the most important hydrocarbon reservoir in Iran. The large quantity of the produced oil in Dezful Embayment is from this formation. Thin section studies in this formation ...
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Asmari Formation (Oligocene - Miocene) is the first fractured proliferous carbonate reservoir that ever known in the world and is the most important hydrocarbon reservoir in Iran. The large quantity of the produced oil in Dezful Embayment is from this formation. Thin section studies in this formation lead to identification of eight microfacies related to the homoclinal ramp with three subdivisions (inner ramp, middle ramp and outer ramp). Many diagenetic processes such as; micritization, neomorphism, bioturbation, dolomitization, dissolution, cementation, mechanical and chemical compaction, fracturing have affected the Asmari carbonates in studied oil field during eogenesis, mesogenesis and telogenesis processes. Three sequences (third order) have been identified based on sequence stratigraphy studies. Based on all results from this study it could be pointed out that; dolomitization, dissolution and cementation are the most important factors that controlled the reservoir quality in this field. Cementation (calcite and anhydrite cements with different fabrics) reduced reservoir quality in different facies. Seemingly, fabric destructive dolomitization increased reservoir quality with creating intercrystaline porosity in mudstone facies and connecting isolated pores (via dissolution) in most of facies. Dissulotion has prime importance where occurred and increased reservoir quality. Contrasting to the other Asmari hydrocarbon fields in Zagros which fracturing is the most important factor in increasing reservoir quality, in Naft-Safid oil field, most of fractures have been filled by calcite cement. Thus, diagenetic imprints (such as dissolution and dolomitization) have more effects on increasing reservoir quality than fracturing.
Petroleum geology
Bita Arbab; Davood Jahani; Bahram Movahed
Abstract
The Aptian Shuaiba deposits, in southeastern of Persian Gulf due to having resistivity less than 6 to 1 ohm.m, is considered as low resistivity pay zone. On the basis of experimental studies 8 microfacies defined which settled in a carbonate platform of homoclinal ramp model that belong to outer, ...
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The Aptian Shuaiba deposits, in southeastern of Persian Gulf due to having resistivity less than 6 to 1 ohm.m, is considered as low resistivity pay zone. On the basis of experimental studies 8 microfacies defined which settled in a carbonate platform of homoclinal ramp model that belong to outer, middle, inner ramp. Existence micro porosity in the microfacies is main reason for lowering resistivity. Various digenetic process are seen such as micritization and pyritization which have noticeable impact on declining resistivity. Lønøy method applied to address pore throat sizes which contain Intercrystalline porosity, Chalky limestone, Mudstone micro porosity. Pore systems are at class 3 Lucia. NMR logs and core data have been used for defining reliable water saturation and reservoir characterization. Results explain that decreasing of resistivity in pay zone is related to texture and grain size variation not being existence of moved water .Irreducible water estimate for this reservoir between 30 to 50 %.
Petroleum geology
B Soleimani; M. S. Ravanshad; Ehsan Larki
Abstract
Petrophysical and lithological parameters study of Ilam reservoir in Ahvaz oil field is the main aim of the present research work. Ilam Formation consisted lithologically of limestone, dolomitic limestone, and less quantity of scattered shales. Facies changes are also observed through the formation. ...
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Petrophysical and lithological parameters study of Ilam reservoir in Ahvaz oil field is the main aim of the present research work. Ilam Formation consisted lithologically of limestone, dolomitic limestone, and less quantity of scattered shales. Facies changes are also observed through the formation. On the basis of petrophysical parameters distribution the reservoir divided into 4 zones. The results indicated that shale volume calculated by CGR log, as a shale index, is less than 10% and so the Ilam reservoir is clean formation. Shale quantity is low in zones 2 and 3 than zones 1 and 4. However, the shale volume is very less but its effect on petrophysical parameters especially porosity and permeability is intense. The Ilam Formation is estimated to have 26.8 % water saturation and 3.3% of irreducible water saturation. Middle part is characterized by low rate of water saturation compared to other parts and along with effective porosity average in the range of 14.7%. Calculated permeability average is 8.3 mD. Permeability variation is indicating a direct relation with the porosity. All these results are emphasized that the middle part (zones 2 and 3) is in better condition in view of oil potential and hydrocarbon reserve in comparing to other parts.
