نشریه زمین شناسی نفت ایران
سال هشتم شماره 1 (پیاپی 15، بهار و تابستان 1397)

The production of oil and gas in oil and gas fields is accompanied by production of water (Produced Water). Most of the reservoirs at the beginning of production have fresh water; but with passing time due to the increase in productions and decrease in pressure of reservoir, the produced water gradually becomes saline. The saline Production water causes severe corrosion in pipelines and well head facilitis leading to reduction in gas production. Determining the origin of salinity for reducing the salinity is most important. Khangiran gas field is located in the northeast of Iran which composed of two separate gas formations, Mozduran at lower and Shurijeh at the upper part. The produced water samples were collected from fresh and salty wells in the Mozduran reservoir as well as two deep samples from brine below the gas reservoir (at depth of 3 km) for comparison and different analyzes. The Mozduran reservoir has two major problems, high salinity of the produced water, as well as the volume of water produced, rendering some wells unexploitable. The results revealed that two deep water samples have different behaviors. The deep sample No. 17, taken at a higher elevation than sample No. 13, showed the signs of salt dissolution; whereas the brine from sample no.13 had the origin of the evaporated old sea water. Therefore, any of these brines in the Khangiran reservoir can be the possible source of salinity in produced waters. The saline produced water samples showed a similar behavior to brine sample no.13. The source of fresh produced water is also the condensation of water vapor in the reservoir during production.

Today, oil industry significantly relies on the precise determination of rock reservoir properties, which reduces the costs and risks of production planning. The reservoir rock always is compacted by pressure drop of the reservoir, which rises effective stress, reservoir compaction and alterations of reservoir properties. As these pressure variations can considerably affect petrophysical properties, in this study, several carbonate reservoir rock samples with different fabric and porosity type (according to CT scan and Archie classification analysis) subjected to cyclic and short-term loading from 600 to 6000 psi. Their petrophysical and compressive properties including pore volume, permeability and compressibility were measured using CMS-300 apparatus. Moreover, structural analysis and heterogeneity of core samples were analyzed by CT scan images. By performing this study, it will be possible to identify the value of the hysteresis effect on the reservoir rock samples as a result of increasing and decreasing of the pressure during cyclic loading. The obtained results show that, pore volume and permeability are both decreased due to loading, whereas reduction of the permeability is several times than the pore volume ones. Moreover, this reduction of pore volume is less severe in vuggy porous samples that shows the effect of heterogeneity and porosity type on hysteresis. Also, the results obtained from the behavior of the reservoir rock under various pressure conditions can provide a suitable design for gas injection studies to enhance oil recovery and also natural gas storage.

In this study, sedimentary environment and depositional sequences were reconstructed based on distribution of microfacies in the sequence belong to the Qom Formation in the Kahak area. The formation was formed alternation of shale and limestone. The boundary between the Qom Formation and the volcanic rocks is unconformable. In addition, the Upper Red Formation in the Kahak area unconformably overlies the Qom Formation. In the study area, 6 microfacies, and 1 terrigenous facies (shale) for the Qom Formation were identified by study of these rock samples. The Qom Formation was deposited in an open-shelf carbonate platform in the study area. This platform can be divided into two environments that the environments consist of the inner shelf (restricted lagoon and semi-restricted lagoon) and middle shelf. Finally, two third-order sequences were identified based on distribution of microfacies in the Kahak area.

The present paper tends to analyze the pore structure of Organic rich carbonaceous rock in 4 samples from Upper Jurassic Sargelu and 5 samples from Lower Cretaceous Garau formation using low pressure nitrogen adsorption. TOC content of Garau samples ranged between 0.64 wt% and 5.21 wt% (mean 3.2 wt%).TOC varied between 0.12 and 10.94 for Sargelu samples. XRD results shows that carbonates are the dominant minerals, followed by quartz and clay minerals. The calculated total pore volume vary between 0.6 cm3/100g to 2.5 cm3/100g with the mean values of 1.4 cm3/100g. A positive linear correlation were found between TOC content of measured samples with pore structure parameters. Due to the larger variation of TOC content this relationship was more obvious for the Sargelu samples. The calculated fractal dimension ranged between 2.45 and 2.81 emphasizing the irregular pore surface of the measured samples. Based on the result of this study organic matter content is recognized as a controlling factor for pore structure and fractal characteristics of the Garau and Sargelu samples.

Fault identification and investigating their evolution is of special importance in the exploration and development of hydrocarbon resources. Success in exploration and development of hydrocarbon fields, need to recognition of petroleum systems and in this regard one of the most important topics is identifying faults and their extension condition as a main fluid migration path, specially in deeper zones. Faults and fractures have crucial role in making high permeable and porous segments and cut reservoir and cap rock in the fluid migration path. In addition, for maximizing the production of hydrocarbon from reservoirs and also for reducing the risk of drilling, it is necessary to gain information about geometry and nature of faults of reservoirs. In this paper, the purpose is investigating the performance of combination of neural networks and Fault Likelihood auto-tracking algorithm for identification and interpretation of faults in seismic data. At first using the Dip-steering feature of software, the early filter for accurate identification of dip of structures in the data, have been designed and applied. Then with designing and applying the appropriate filters, the seismic data have been improved. After that proper seismic attributes for fault identification have been calculated from seismic data. With picking fault and non-fault points from data, a supervised neural network using the selected attributes was formed and after training the network, the appropriate output achieved. Then the output of neural network has been used as a input for Thinned Fault Likelihood auto-tracking algorithm. The output of this part contains a volume of tracked faults. Finally using sub-tools of TFL and optimal setting of parameters, 3D fault planes has been interpreted and extracted.

One of the most important stages in the hydrocarbon reservoirs morphology is the identification of rocky type. In order to construct an efficient and correct model of a hydrocarbon reservoir, identification of rock types is one of the essential parameters in reservoir modeling. and its consequences are found in the identification of rock types. The aim of this study is to compare different methods of determining rocky type and understanding the hydraulic flow unit distributions in order to assess the quality of reservoir of Razak Formation with sandstone carbonate lithology, marl and anhydrite to San Oligocene to lower Miocene. In this research, the experimental results of porosity, permeability and capillary pressure curves for 84 samples with porous microscopic sections Related to a 46-meter drill bit in one of the important fields of southeast of Iran were analyzed. The petrographic studies were conducted to investigate the changes of the features in the reservoir section with Razak formation and resulted in the identification of eight microfeatures( The MF1 packstone and Wackstone are at a depth of 2829 meters- The MF2 is the grinstone packstone at a depth of 2844 meters-the MF3 is the wackstone mudstone at a depth 2856 meters-the MF4 is the grinstone at a depth 2859meters –the MF5 is the mudstone wackstone are at a depth2848 meters – the MF6 mudstone at a depth of 2838 meters the MF7is the wackstone mudstone at a depth 2840 meters- The MF8 is a wackstone with sandstone depth of 2831) meters- in open Marin lagoon and fluvial clastic systems. In order to determine the rocky species and assess the flow units based on the core analysis results, four petrophysical classes were identified using the Lucia method. The petrophysical category number 1 has the best reservoir quality and the fourth category has the weakest reservoir quality. Also, the flow units were identified and separated using Amalufee and Lorenz's methods. Based on the Amalufee method, in the reservoir section of the Razak Formation, seven flow units have been identified, the sixth and seventh stream units were the best and one was the weakest reservoir segments among the seven units of the flow. Also, based on the analysis of capillary curves, six rocky species were distinguished, based on which the rocky type number five and six have the best quality. Also, using Geology software cross-sections, it was revealed that the main part of this section is sandstone with clay. The presence of gas in the formation causes cross-sectional deformation of samples to the northwest cross-platform. Finally, with the combination of various data, it was found the fossil formation in the study area has five types of rock in which the number 4 rock has the best quality of reservoir and rock number 5 has the largest reservoir and the unit number six is the best.