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Desalination of brackish water can be a good help in dealing with the water crisis. The aim of the present study is to design a geothermal desalination plant using thermal energy from the depths of abandoned oil wells.

This research was done in 1400 on Khark Island in the Persian Gulf. First, a multi-stage sweetening method is selected to use the heat of the abandoned oil well. Then, the methods and structures that help you increase the production of sweet milk using this option were examined using EES software, for which 4 different types have been presented, including:<!-- [if !supportLists]-->·  <!--[endif]-->Conventional multi-stage sweetening.<!-- [if !supportLists]--><!--[endif]-->Multi-stage sweetening with secondary preheating.<!-- [if !supportLists]-->· <!--[endif]-->Multi-stage sweetening with secondary preheating and external flash box.<!-- [if !supportLists]-->· <!--[endif]-->Multi-stage sweetening with secondary preheating, external flashbox and internal flashbox

Research findings show that the variable of presence of tourists in this area is influenced by the following life indices including: Economic prosperity, improving environmental quality, reduction of air pollution, improving communication of inhabitants and easy access to public transportation means and improving cultural issues.  

In the final part of this research, geothermal desalination using economic heat from abandoned oil wells using current value method and inflation rates is economically analyzed.

Reservoir oil recovery and efficiency of EOR projects include designed water injection influenced by factors such as oil composition, porosity, permeability, rock mineral composition, porous space distribution, and pore size. The injection of designed water into the carbonate reservoir has always faced many ambiguities. This category of ambiguities has been further investigated and analyzed in this study by examining one of the influential factors, such as polar compounds of oil and its Physico-chemical interactions during the production process. Polar components in crude oil affect the electrostatic interactions at the mineral surfaces, affecting the wettability conditions. This study performed experiments measuring contact angle and spontaneous vascular process on limestone samples. For this purpose, cores with the same conditions are saturated in different oils regarding the percentage of polar compounds. Moreover, they are adjacent to specific components of active ions in designed water. In this regard, using the collected results, we can interpret and study how to participate in the reaction and the effectiveness of polar compounds in the oil. The results show that the amount of oil production due to water injection depends on the chemical composition of the oil and the interaction between water and oil, and in addition to the amount of asphaltene in the oil, it is also affected by the amount of organic carboxylic acids in crude oil.

The process of injecting smart water into carbonate reservoirs has always faced many challenges. In this study, by examining one of the effective factors such as ionic compounds active in smart water, these ambiguities have been further investigated and analyzed. The reaction between three phases, oil, rock and saline, which leads to a change in wettability, requires the presence of ionic compounds active in smart water and active compounds in oil. The presence of these compounds in the desired concentrations is the driving force required to perform ion exchange reactions followed by a change in wettability. In fact, the optimal concentration of active ions leads to the formation of a stable water film and a change in the wettability of the rock. In this study, experiments measuring the contact angle and the spontaneous imbibition deferens process were performed on samples of limestone.  For this purpose, the cores with the same conditions are located in the vicinity of different compounds of active ions in smart water. In this regard, using the collected results, it is possible to interpret and study how to participate in the reaction and the effectiveness of the active compounds of smart water. It can also be concluded that cations in the presence of sulfate ions can have a positive performance at the minimum concentration in seawater and have acceptable efficiencies of about 41% in experimental conditions.

Sarvak Formation is one of the units in the Bangestan lithostratigraphic group with Albian-Turonian age. The shallow sea at the end of the Albian to Cenomanian time has deposited large amounts of the shallow marine carbonates (Sarvak Formation) over a large area of the Zagros basin (Motiei, 1995). The Sarvak Formation has two different facies. At the type section and coastal Fars, shallow marine facies of this formation mostly formed while in the Lorestan area, the facies are belonging to deeper water (Motiei, 1995). The Sarvak Formation is a reservoir of hydrocarbon in the Zagros sedimentary basin. Therefore, a detailed study of this formation, based on microfacies and sequence stratigraphy, will provide useful and valuable information for further exploration in this basin. The purpose of this study was to evaluate the biostratigraphy, microfacies, depositional environment and sequence stratigraphy of the Sarvak Formation.

To approach the objectives of this research, two stages have been taken: Preparation of 195 thin sections from drill cores and cuttings (National South Oil Company), then Laboratory studies of thin sections prepared by binocular microscopy and identification of allochems and orthochems and the preparation of photomicrographs. The identified biozones correspond to biozones named after Wynd (1965). In this study, Flugel (2010) method used to describe the microfacies, and also Reading (1996) and Dunham (1962) methods used to determine rock texture and nomenclature Identification, photography and the creation of the Atlas of microfossils, their distribution in stratigraphic column, representation of identified biozones, and sedimentary sequence lithology in the studied area has been made possible through the study of graphs and logs, thin sections, and the use of various research satellites such as Bolli (1945; 1959; 1966), Postuma (1971) and Caron (1983). Sequence stratigraphy of the Sarvak Formation has been studied based on sequence stratigraphic methods and principles (Haq et al., 1987; Van Wagoner et al., 1988; Emery and Myers, 1996; Simmons et al., 2007).

Based on this study, 5 genus and 2 species of pelagic microfossils and 25 genus and 28 species of benthic microfossils were identified. Therefore, three biozones including Nezzazata - alveolinids assemblage zone # 25, Rudist debris zone # 24, and Oligosteginid flood zone # 26 were introduced that are corresponding to the biozones introduced by Wynd (1965). Based on the studied faunal assemblage, the age of the Sarvak Formation is from Cenomanian to Turonian in the studied wells. The upper boundary of the Sarvak Formation with the Gurpi Formation is discontinuous due to the presence of glauconitic nodules at the base of the Gurpi. According to the regional geology of this area and information from the studied wells, the Ilam Formation and the 30th Wynd Biological Zone (Wynd, 1965), as well as the biodegradation of Wynd (1965) at the top of the Sarvak Formation, are absent. The drilling has not reached the base of the Sarvak Formation, therefore the lower boundary is not clear. 7 microfacies identified in the Sarvak Formation in the studied wells. These microfacies are formed in 3 main facies belts including 1- open sea, 2- shoal, and 3- lagoon. Investigation of carbonate rocks of the Sarvak Formation in the study area shows that the sedimentary environment of the Sarvak Formation in the studied field was a shallow carbonate platform of the carbonate ram type. The Sarvak Formation in the study area consists of 1 complete sedimentary sequence and 2 incomplete sequences, which are generally HST and TST in the studied sections. The HST facies in this sequence originate from a variety of marine microfacies and finished with the lagoon. The TST facies is mainly related to the open marine. Finally, the HST facies is related to the inner and middle parts of the platform; while the TST facies is related to the outer and middle parts of the platform.

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.

Accurate evaluation of pore pressure and fracture pressure are key parameter in well planning and drilling operation. Estimation of these parameters has an important role in reduction in well costs. An inaccurate estimation of fracture gradient may jeopardize whole drilling operation and cause serious problems such as loss circulation and blowout. In this paper, the method of Gene Expression Programming (GEP) has used for developing a mathematical model for prediction of formation fracture pressure. Overburden pressure, pore pressure and Poisson ratio are independent variables in this model. Studied areas include two oil-bearing formations: Kangan and Upper-Dalan in an onshore field which is located near Persian Gulf. A separate model is presented for each formation by using well logging data from two wells. Models developed by using more than 4,300 well logging data from a well. Verification of these models is done with 6,000 data from second well in same formation. Statistical analyses confirm that the models are suitable for fracture gradient prediction so we can use them for estimation of fracture pressure.

Preparing drilling fluids is the most important part of the drilling operation of oil and gas wells that the use of advanced and beneficial technologies in their production can be closer to their performance and efficiency than the ideal values. Colloidal gas Aphron (CGA) based drilling fluids with advanced technology of aphron micro-bubbles and particular for Under Balance Drilling (UBD) are one of the newest technology that is used in the drilling of low pressure reservoirs. With production of aphron oil-based drilling fluid can be achieved together positive and valuable properties of oil-based drilling fluids along with special properties such as lost circulation of aphron based drilling fluids. Stability over time is the most important characteristic of aphron based drilling fluids that can be influenced on desirable rheological properties and control of lost circulation in this type of fluids. In this study, aphronized fluid with 2.14 mole percent surfactant and 15.01 kg/m3 polymer concentration has the highest stability over time, lowest yield loss and the lowest bubble size changes that these concentrations are presented as optimal concentration of surfactant and polymer.

Summary Water and Gas injection are two major enhanced oil recovery methods in Iran. Gas (e.g. CO2) injection, is one of the most applicable methods of enhancing oil recovery in oil fields. In order to study the behaviour of seismic attributes, the compatibility of the prediction made by Gassman theory and GreenbergCastagna equations in the situation of CO2 saturated environment is investigated using lab data. It should be noted that the mentioned equations are based on some assumptions that are not always represent the real situation, thus, some incompatibility is anticipated. Therefore, their predictions are liable to be incompatible with real world wave behaviour. In this research, CO2 in dissolved phase is injected into pressurized sandstone samples in laboratory scale, and elastic waves are utilized in order to investigate the injection process. The variation of the propagation velocity of seismic waves and their amplitudes are studied versus variation of effective parameters e.g. confining pressure (close to reservoir pressure), pore pressure (close to reservoir pressure), transmission wave frequency, and CO2 density and phase. We have also used the collected laboratory data for wave propagation at supercritical saturation state to investigate the compatibility of the prediction made by Gassman theory and Greenberg-Castagna equations. Based on the results of various laboratory experiments, we can conclude that some of the developed equations are useful for estimation of velocity and amplitude of seismic waves. Verifications confirm that compatibility of the developed equations with laboratory results are more than 90 percent, and thus, the developed equations can be preferred to other related popular equations.
Introduction Rock physics has an effective role in the estimation of petrophysical and reservoir parameters e.g. porosity, permeability, rock type, saturation, pore pressure, and fracture density using seismic attributes. As a result, various seismic attributes such as velocity, frequency and phase are used in order to estimate the above-mentioned petrophysical and reservoir parameters (Dodds et al. 2007, Adam 2006, Ruiping et al. 2006, Avseth 2005, Gray et al. 2002). In recent decades, various empirical relations are also developed for this purpose (pennebake 1968, Eaton 1972, Reynolds 1970, Domenico 1977, Castagna et al. 1985, Greenberg and Castagna 1992, Castagna et al. 1993, Krzikalla and Muller 2007, Toms et al. 2007, Lebedev et al. 2009, Han et al. 2010, Han et al. 2014, Liu et al. 2010, Eftekharifar and Han 2011). Gassman theory and Greenberg-Castagna equations are widely utilized as basic rock physics equations in world oil fields. However, these equations are based on some unreal hypotheses which cause their results to be not fully compatible with real situations, for example these hypotheses do not consider the distribution of fluids, and also, do not pay attention to the real situation of the rock and fluids; e.g. pore size, pore shape, fracture density, fracture aperture, heterogeneity, the fabric of matrix, pore pressure, confining pressure, fluid type, saturation, fluid distribution, viscosity, compressibility index, etc. Therefore, these equations need reform, especially when rock type, fluid type and reservoir situation varies. In this paper, based on laboratory experiments, some empirical rock physics equations are developed that are more compatible with reservoir conditions, and present a new approach for estimation of velocity and amplitude of seismic waves.
Methodology and Approaches In this research, a core holder has been designed in which measuring and controlling the confining, radial, axial and pore pressures have been feasible. Two transducers are put around the caps of core holder, in order to send and receive seismic waves. Transducers are in contact with plugs. The studied plugs having various grain sizes are taken from Berea sandstone formation in southwest of Australia. Three different CO2 densities or concentrations are injected and dissolved into plugs saturated with distilled water. In the next stage, elastic waves having different frequencies are passed plugs under various pressure/density situations, and consequently, velocities of the waves are recorded. Based on these laboratory experiments, some equations are developed using multi-regression method that are more compatible with reservoir conditions
Results and Conclusions In this paper, some novel equations, based on laboratory experiments, have been developed that not only are accurate but also are generalized. These equations or relations present a new approach in estimation of the velocity and amplitude of seismic waves. Based on the results, the authors of this paper prefer to give some practical recommendations as follow: • All laboratory tests have been carried out in room temperature, and thus, the authors suggest that a similar research to be repeated in the reservoir temperature, and new equations to be developed. • In the current research, just two seismic attributes (velocity and amplitude) are studied. The authors suggest that other seismic attributes are also investigated in future studies. • The majority of Iranian oil fields are carbonate reservoirs while this research has been carried out on sandstone. Thus, the authors suggest that similar studies have been carried out on carbonate plugs. • Repeating laboratory tests with reflected waves will help to approach more real results. • In all laboratory tests, the authors have investigated the effect of pressure growth on the tests. It will be useful that other researchers investigate the effect of pressure drop on the results.

Formation fluid migration to the cement column is one of the most common and costly problems occurring in most gas and some oil wells, which could lead to some hazardous consequences. Some major oil companies have designed special additives to mitigate or preferably eliminate the phenomena of gas migration. With respect to most Iranian oil and gas fields, the use of anti gas migration additives is highly required. In one gas filed as a case study, despite the application of anti gas migration additive to the cement recipe, the problem of gas migration through cement is still occurring. In this investigation, the process of quality control of the additive by use of FMA utility has been done and the effects of using this special chemical on all cement properties have been studied. Results showed that adding anti gas migration additives is not the only solution to overcome gas migration problem in cements. The main key in using anti gas migration additives is to optimize additive consumption and design slurry with acceptable properties such as zero free water, total API fluid loss value less than 50 cc, early compressive strength development in less than 5 hours, right angle set pattern in thickening time test (time between 30 and 70 BC must not exceed 25 minutes) and rapid gel strength development between 250 to 500 lb/100 ft2. Fortunately, by use of special anti gas migration additive from domestic source which is called PK-90 all aforementioned criteria had been met.

Gas condensate reservoirs are generally deeper and are found at higher pressures and temperatures relative to oil reservoirs. Light hydrocarbon compounds are parts of crude oil and gas condensates, which have different types of structures. 7-carbon hydrocarbons with open chain and branch ring structures can be considered as good indicators for the recognition and origin of organic matters, source rock characteristics, etc. In this study, three fluid samples of three independent gas fields in southern Iran, from Kangan and upper Dalan formations (with similar geochemical characteristics), are subjected to detailed hydrocarbon analysis (with the ability of the identification of molecular components of the organic compounds) and other PVT experiments, and changes in the concentration of specific compounds having 7 carbons or less in different reservoir conditions were studied. The results showed that according to the overall parameters, samples A and C were similar and both were different from sample B, which was attributed especially to the difference of reservoir conditions between samples A and C with sample B. Also, the paraffinicity property of fields initially decreased but then increased from A to C, and, likewise, field B represented vast evidence for the occurrence of biodegradation processes. Figures showed that the source rock of sample C had obviously the terrigenous origin, but understanding the origin of samples A and B were carried out using various diagrams and it was determined that the two fields had the dry origin. It was also found that the mixing process of reservoir contents having organic matters with that of the other formations have probably occurred in sample C.

Drilling low-pressure reservoirs is associated with economic and technical issues; thus the development of these fields has been non-profitable. One of the major drilling problems of these wells is the uncontrollable loss of mud in fractures. Nowadays, new drilling technologies use sustainable micro bubbles with diameters between 10 and 100 micrometers and polymer to solve this problem. Unique characteristics of micro bubbles in water-based mud forms an inner elastic, firm, and solid connection in pores and fractures, which minimizes the penetration of tiny air bubbles deep into the network. This is simply a micro blockage which is washed and goes away with a reverse flow when the production starts and this reduces the cost of the stimulation processes of the well. These are non-Newtonian fluids and their apparent viscosity is higher in comparison with the water-based mud. Their behavior is similar to pseudoplastic drilling fluids and they can be modeled with a power law model. This study investigated the rheological properties of micro bubbles drilling fluids with different concentrations of polymer and surfactants; it was shown that increasing the surfactant concentration increased the viscosity of micro bubbles and the size of bubbles at a fixed polymer concentration; also, the size of the bubbles was reduced by increasing polymer concentration at a fixed amount of surfactant

Analyze of parameters which influence the petrophysical Properties of reservoir rocks is necessary in dynamic model simulation of reservoirs. According to the relation of cementation factor and reservoir pressure changes, cementation factor is the most effective parameter in water saturation determination in the mentioned model, so the study of the effect of pressure on cementation factor is necessary. In this study, firstly carbonate core samples of a gas reservoir, in the south of Iran was classified by hydraulic flow unit delineation method. Then their cementation factors were determined by Archie equation and best fit curve method at ambient, 800, 2000, 3500, and 5000 psi pressures. The changes in cementation factor values due to increasing overburden pressure were evaluated in each hydraulic flow unit and their relationship with flow zone indicator (FZI) were studied by experimental equations (for 4 flow units 0.95

Keywords: cementation factor, hydraulic flow unit, saturation, overburden pressure

Qualitative analysis of petroleum reservoir rocks is still one of the most important topics of core laboratories and directly affects hydrocarbon-in-place، fluid flow، and prediction of field performance. Magnetic Resonance Imaging (MRI) as a non-invasive، millimeter resolution technique which only images fluids in porous media fits this purpose perfectly. Magnetic resonance is a radio frequency spectrometry، based on excitation of nucleus energy levels which can exploit a wide range of information on the saturation fluid، geometry of pores، and diffusion. Using magnetic gradients and signal encoding، this can be used as a tomography technique. Determining porosity regardless of rock lithology، reservoir rock quality، bound and free water (which presents production potential) and potential permeable tight beds are applications of this method، from among many others. Recent advances in imaging techniques along with new software and processing methods has resulted in exploiting the images containing valuable physical information. The main aims of this study are qualitative investigation of core sample، determining the number and distribution of vugs، presenting three-dimensional models and comparing this method with other conventional methods. We acquired images of cores adequate for revealing characteristics of matrix، vugs، and other different porosity types in carbonate rocks as well as their interaction. The images in the form of matrices of MR signal were analyzed using both image analysis and physics of MR signal. Studied samples are a selection from one of southern Iranian carbonate reservoirs، cleaned using Soxhlet extraction، dried in oven and saturated with synthetic reservoir brine. Rock type، pore-filling fluid، the MRI imaging hardware and software، pulse sequence، and image processing affect such study results. So، impacts of several items were considered and best available pulse sequence parameters were set. Presence of ferromagnetic minerals adversely affects image quality، so samples bearing these minerals are very difficult to image in high fields and have to be imaged with special pulse sequences and systems. Samples without ferromagnetic minerals، as in most carbonate rocks، can be imaged in high fields، so because of the superior quality of high field imaging، this method is used in our carbonate samples. Validity of MRI images was verified using histogram analysis of water، rock and air segments of the images subsequent to acquisition. Reference fluids، brine (the pore-filling fluid) and air، helped us in matching and comparing histograms and check the validity of signal from porous sample. In image analysis we utilized histogram، field of view، and segmentation techniques. Results of this analysis after using physical models of MRI signal in porous media led to numerical and visual models of rock samples. In addition to visual models of porosity، we prepared visual models of mean-T2 of invaluable to quantitative and qualitative study of porosity، ultimately resulting in determining fraction of vuggy، moldic، and inter-particle porosity. This model was constructed by superposition of image slices. Inter-particle porosity cannot be determined from sub-millimeter MRI image analysis، so it is calculated from the physics of MR signal. We determined the accuracy of the method in comparison with other conventional experiments such as helium porosimetry and petrographic image analysis which revealed reasonable accuracy of the method in determining porosity types and visualization. Effect of several items in the accuracy of this method is proposed. First، gravimetry porosity is always lower compared to the helium porosimetry، and porosity calculated from MRI imaging only is affected by water saturation of the sample، so MRI porosity should always be compared with gravimetry porosity. Second، MRI images are not only sensitive to water in porous samples، but also sensitive to pore size of the sample. Water in very fine pores is not shown in images unless echo time is set to 1-3ms، not possible in our study because of hardware limits. Third، magnetic field inhomogeneity can account for up to nine percent of signal intensity. This study obtained a new perspective in using MRI imaging for qualitative study of porosity and determining share of porosity types.

3D reservoir property modeling is one of the most important steps in fluid flow simulation. A more accurate model would provide a more realistic reservoir simulation. In this study، four different geostatistical approaches، including Kriging، collocated cokriging، sequential Gaussian simulation (SGS)، and Cosimulation were applied to well data for 3D porosity model building. Initially، Kriging method was based only on well data and utilized for porosity estimation. Then، seismic acoustic impedance data as a secondary seismic attribute was used in collocated cokriging algorithm for 3D porosity modeling. Kriging and collocated cokriging-based SGS approach were also used for 3D model building. The cross validation of all the four approaches revealed that the best model obtained using co-simulation with secondary data.

Rock physics is the major tool to describe physical property of reservoir rocks; such as porosity, permeability, degree of saturation, property fluid that saturated, shape of pores, compressibility and etc via studying ultrasonic wave transmitting through a rock sample. Between these parameters, porosity and degree of saturation are more effective on elastic wave velocities which have been studied extensively in recently years. Amplitude of acoustic waves is a function of acoustic impedances (velocity and density) could be used to study lithology, pore fluids and saturation. In this paper we studied how main characters wave (velocity, amplitude, frequency) changes related to two main reservoir characteristics (pore pressure and confining pressure). In our study, we transmitted ultrasonic waves in different frequencies through a sandstone core in reservoir pressure condition. Analysis confirmed that similar to previous studies, amplitude of transmitted signal is a more sensitive attribute to pressure changes rather than velocity of the waves.

When we are talking about economic decisions concerning management of an exploratory field or reservoir، undoubtedly، the correct understanding and realistic explanation of reservoir can lead us to make valuable decisions and choosing appropriate plan in order to improve reservoir management and exploitation; Recoverable oil in place is the most important factor which affects these decisions. This study has been performed in order to make a three dimensional model of structure، stratigraphy، and petrophysical properties of one of Southern Iran reservoirs. Well logging and petrographic data as well as core analysis information were combined and put into an integrated workflow to took advantage of them to build probabilistic models of properties like porosity and water saturation (SW)، using geostatistical routines such as Kriging and Sequential Gaussian Simulation (SGS). Comparison of these methods clearly shows that results of Sequential Gaussian simulation are more acceptable. Finally، volumetric calculations have done using the most realistic model outputs and parameters. The averages of porosity، SW and oil in place have estimated 21%، 52%، and 270 million barrel respectively.

An important step in the modeling of two-phase gas and oil flow is to have the reliable relative permeability functions. None of the previous conventional methods can predict the consistent and accurate relative permeability values to show the effect of near miscibility on the qualitative and quantitative behavior of relative permeability functions under near miscible conditions. The main contribution of this work is to select the optimum approach to relative permeability determination based on the classification of the available relative permeability methods and comparing their results in order to extract more accurate relative permeability values under near miscible conditions. In this work, the unsteady state displacement experiments were performed on two different reservoir rock samples (i.e. a dolomite and a sandstone core plug sample from the west of Iran). In addition, CO2 and light oil samples as injection fluids were used to decrease the variance error. Also, by the selection of the best relative permeability methods, the bias errors are decreased. In this study, inverse modeling is used with the Civan and Donaldson method as the initial guess for 1-D, two-phase flow simulation. The results show that the history matching as the optimum method presents a reformed relation in order to generate the relative permeability values more consistent to laboratory data under near miscible conditions. Finally, this reformed relation can be embedded in fluid flow simulators to simulate the near miscible gas injection more precisely.

The relation between compressional wave velocity and porosity depends on porosity, porosity type, mineralogy, saturation, and pressure in carbonate rock. Therefore, data points are scattered in a velocity-porosity cross plot. In this study, two methods of rock typing in carbonate rocks are analyzed to investigate the relation between compressional wave velocity and porosity. For this purpose, flow zone indicators and velocity deviation values are used. Flow zone indicators are determined from differences between sonic velocity and the velocity obtained from Wyllie time average equation using neutron porosity. The results show four hydraulic flow units with flow zone indicators from 2.23 to 19.95 and four rock types based on velocity deviation values from 139 to 1135 (m/s). Moreover, the results show that the rock typing based on velocity deviation values is more accurate than that obtained by flow zone indicators. The average value of correlation coefficient is 95% for grouping based on velocity deviation values, whereas this value is 67% for grouping based on flow zone indicators.

The determination of fluid saturation is vital for the estimation of hydrocarbon in place which is the base for economic decision making about reservoir production. Archie’s equations are the most prevalent equations used for saturation calculation. One of the important parameters in these equations is saturation exponent. Saturation exponent has fundamental difference comparing with other parameters which are cementation exponent and tortuosity. Cementation exponent and tortuosity mostly depend on rock type but saturation exponent depends on the distribution of fluids and therefore the hysteresis of saturation during imbibitions and drainage and also wettability. The purpose of this research is an investigation into the effect of saturation hysteresis and wettability on saturation exponent. The saturation exponent was measured from primary drainage to secondary drainage with a four-electrode system at reservoir temperature with reservoir fluids on some cylindrical core samples. Dynamic porous plate technique was used، for which full capillary pressure curves and wettability with combined Amott-USBM were determined simultaneously. It was concluded that the saturation hysteresis affects saturation exponent in different samples during imbibition and drainage and cause it to range from 0. 1 to 0. 66; the variations were higher in oil-wet samples than water-wet samples.

Relative permeability can be measured directly from cores, but due to problems such as unavailability of experimental results of direct relative permeability measurement, indirect techniques also have been used to calculate relative permeability. One of these methods is estimating relative permeability curves from capillary pressure data that the reliability of this method for approximation of liquid-gas relative permeability curves had thoroughly investigated. However, there is not enough information to conclude which method is the standard one for calculating oil-water relative permeability curves. Various capillary pressure techniques such as the Corey, Brooks-Corey, Li-Purcell and Li-Burdine methods were utilized to calculate oil-water relative permeabilities using the measured oil-water capillary pressure data in drainage process in an oil-wet Carbonate reservoir. Despite wide popularity of Purcell and Burdine methods for calculating relative permeability, new Li-Purcell and Li-Burdine methods were used. The calculated results were compared to the experimental data of oil-water relative permeabilities measured in a Carbonate reservoir. The Corey and Brooks-Corey models are shown an acceptable and nearly exact match with the measured oil relative permeability values. However, the Li-Purcell and Li-Burdine models underestimate the values for wetting phase in most cases. It is also worth mentioning that, except Li-Purcell method, the results of all other methods for calculating non-wetting phase relative permeability are almost the same and overestimate the values. Then, rock typing on the basis of pore throat radius at 35% mercury saturation were done and the accuracy of each model were examined for all rock types. Results of this work revealed that calculation of oil-water relative permeability using the capillary pressure data is also a reliable technique in oil-wet carbonate reservoirs.

In this paper, the role of molecular diffusion in mobilization of waterflood residual oil is examined. A moving mesh method is applied to solve the moving interface problem of residual oil blobs swelling by Co2 diffusion through a blocking water phase. The results of this modeling are compared with experimental results of a 2D glass micromodel experiment. Although, the solution method is applied for a 1D system, a good agreement between numerical and experimental results validates the solution method. In this method a fixed time step is proposed. Furthermore, the results of this method have been compared with the results of the Grogan’s finite difference method. This supposed that, the mesh network is fixed and time step increasing will be continued until the oil-swelling equal to one spatial step size.

Prediction of permeability that is one of the most important parameters in oil and gas reservoirs is probably the most challenging issue geologists، petrophysicists، and reservoir engineers have to deal with. This parameter control fluid flow in production stage. The most reliable data of permeability are taken from laboratory analysis of cores. Since coring is a costly and time consuming operation، researchers have tried to predict this parameter from other methods. Empirical equation is one of these methods، but results of these equations are not satisfied for all lithology and reservoirs. So far، several studies have been carried out for the estimation of reservoir parameters using intelligent systems. These studies indicate the successful role of these methods such as fuzzy logic، neuro-fuzzy and genetic algorithms for reservoir characterization. In this study، we try to compare results of these two methods (empirical equations and intelligent systems) for permeability prediction in a carbonate reservoir. For this purpose، petrophysical and core data of four well in a carbonate reservoir in the Southern Iran were used. At first، using empirical equations permeability was calculated for the test well; then using data of three wells، intelligent models were constructed. A forth well (test well) from the field was used to evaluate the models. The results show that fuzzy logic result (with R2= 0. 88) is the best method for prediction of permeability in the studied reservoir. Also between empirical equations، result of Wyllie-Rose equation is better than others. Finally we offer the constructed fuzzy model (as a best predictor) for permeability prediction in the studied reservoir.

Due to majority of relative permeability in reservoir engineering studies and its dependency to some physical properties, relative permeability measurement is the most complicated task in special core analysis studies. Equilibrium in front flow during flooding and recognizing the end effect capillary pressure in relative permeability tests is very important. For this reason the usage of in-situ saturation measurement methods has a paramount importance. Also performing SCAL tests in reservoir conditions and using reservoir oil creates correct and real data for reservoir engineers to apply in reservoir models. In this study, the goal of which is the determination of in-situ saturation during flooding in reservoir conditions, first four plug samples from Asmari formation were selected and thin section studies were done to recognize the lithologies and important features. Then using relative permeability apparatus in ambient condition, the average saturations of fluids in the cores were determined by measuring the volume of fluids expelled from the samples in the flooding test and the relative permeability curves were plotted. In the next step using x-ray relative permeability apparatus, the relative permeability experiments in the reservoir conditions were performed and the value of in-situ fluid saturation and the average saturation were determined via measuring the intensity of x-ray passes through the core. The results obtained from relative permeability tests in ambient and reservoir condition were then compared. Dead crude oil from Asmari formation has been used in all experiments.