جستجوی مقالات مرتبط با کلیدواژه « Well Log » در نشریات گروه « مهندسی شیمی، نفت و پلیمر »

In recent years, enhanced oil recovery (EOR) methods have received more attention because of the increase in demand and decrease in oil reserves. One of these methods is water injection. Due to the structural complexities and sedimentology of most of Iran’s reservoirs, the success of EOR methods, particularly water injection, is associated with high uncertainty. Therefore, monitoring and controlling the injection process using four-dimensional seismic surveys is necessary to reduce the operational risk and increase the production rate. In this study, the feasibility of seismic operation is investigated to monitor the water injection process in two reservoir formations of Burgan (sandstone) and Yamama (carbonate) in one of the oil fields in the south of Iran in zero, one, and three-dimensional scales. For this purpose, first, a comprehensive study was performed on the existing rock physics models, and the appropriate rock physics model covering most of the effective parameters was selected. Then, the changes in seismic response caused by the three scenarios of formation water injection, seawater injection, and smart water injection were investigated in each formation. The results obtained in the zero-dimensional scale showed that the acoustic impedance changes by 4.5-7% for different scenarios in both sandstone and carbonate reservoirs. To perform one-dimensional studies, synthetic seismic data were generated using well logs and for different scenarios of rising oil-water contact. The results of one-dimensional modeling indicate that four-dimensional seismic data can record any displacement over 3 meters in oil-water contact in the Burgan reservoir and over 7 meters in Yamama. To conduct studies on a 3D scale, 3D synthetic seismic data were generated using static and dynamic models of Burgan and Yamama reservoirs. Feasibility studies using 3D seismic data also indicate the possibility of success of 4D seismic data for monitoring changes in the fluid contacts of both Burgan and Yamama formations on a reservoir scale. Therefore, 4D seismic operation in the selected field is recommended for monitoring and optimizing the production plan and suggesting suitable locations for drilling new wells.

Quantitative heterogeneity presentation is very important to compare the amount of heterogeneity in different reservoir characteristics in carbonate reservoirs. The aim of the present study is to quantify the heterogeneity by calculating the heterogeneity log and its application in investigating the heterogeneity of porosity and permeability in the Late Barremian-Early Aptian Darian carbonate Formation in the central part of the Persian Gulf. In order to calculate the heterogeneity logs, the well log data of gamma ray, bulk density, neutron porosity, acoustic and deep resistivity and the statistical methods of Lorenz coefficient and coefficient of variation have been used. Results show that the calculation of the heterogeneity log provides the possibility of quantitative comparison of the heterogeneity between different parts of the reservoir for different purposes. Heterogeneity calculation with both methods is efficient for calculating heterogeneity, but it should be noted that the coefficient of variation for the maximum heterogeneity does not have a specific range like the Lorenz coefficient. Also, increase in porosity is associated with a decrease in the amount of heterogeneity in the heterogeneity logs of deep resistivity, acoustic, neutron porosity and density. Unlike other logs, gamma ray heterogeneity log has little direct relationship with porosity in Darian Formation. Two types of neutron porosity heterogeneity and deep resistivity are the most used in determining the reservoir properties in this formation. Permeability shows a weak relationship with heterogeneity logs. In bioclast wackestone microfacies of carbonated units with high porosity, less heterogeneity is observed. Also, units with higher porosity are thicker and therefore exert stronger mean effects on heterogeneous areas. High variability in porosity and permeability causes higher heterogeneity. This is also the case about lithology and clay minerals. Heterogeneity changes at facies change boundaries. Therefore, heterogeneity log can be used to investigate geological heterogeneity, porosity, permeability and reservoir zoning.

Carbonate reservoirs are very complex and heterogeneous. Overcoming heterogeneity is important and necessary for accurate reservoir characterization. Dalan-Kangan formations, as the largest non-associated gas reservoir of the world, are heterogeneous and complex due to the influence of the sedimentary environment and diagenesis processes. Carbonate reservoirs are routinely studied using laboratory data. The use of well logging instead of using laboratory methods is very cost-effective in reducing time and cost. To overcome the heterogeneity by acoustic log, samples of Dalan-Kangan carbonate formations were prepared. A total of 87 limestone thin sections were evaluated by petrography, routine core analysis, and sonic velocity. Porosity, permeability, sedimentary textures, pore types, and diagenetic processes were determined precisely. From the studied well, well logging and acoustic logs were also available. After data quality control, the acoustic log was converted to velocity. Velocity-porosity model was constructed based on the differential effective medium (DEM) approach for different values of equivalent pore aspect ratio (EPAR). The results show that moldic, vuggy, interparticle, and microporosity pores have the largest aspect ratio, respectively. Due to their spherical shape and high aspect ratio at the given porosity, moldic and vuggy pores have higher velocity than flat and narrow pores. Through the geometrical shape and pore type and by using the acoustic log, the rock types were determined. These rock types clearly showed the porosity evolution, permeability changes and diagenetic processes that have been occurred in Dalan-Kangan reservoirs.

Determining reservoir parameters is very important which is usually conducted in laboratories, but, it is an expensive, time consuming and difficult process.Therefore, in this study, NMR log has been used to determine porosity, permeability, capillary pressure in the upper part of Dalan Formation in well SP-A of South Pars gas field. In this method, the capillary pressure versus Sw was plotted from the T2 distribution of NMR log and then compared with the curves obtained from mercury injection in the studied well. High Correlation coefficient of 0.93 and 0.98 are obtained by comparing core derived versus NMR porosity and Timur permeability (mean NMR Timur permeability 80 md) for the reservoir zone (k4). According to well log and software evaluation mean total porosity is 15.5% and mean effective porosity is 11.9 % for the study area. Low shale volume, adequate porosity showed that talent the reservoir of the study area is high.

The study of sedimentary characteristics of carbonate formations as one of the main hydrocarbon reservoirs is important. In this research paper, we used thin section, and petrophysical logs data to analysis of facies, sedimentary environment and diagenetic variation of the Ilam Formation (Bangestan group). Thin sections petrography revealed that the Ilam Formation which was deposited as a full series in western part of the Gachsaran oil field and characterized by a neritic facies indicating a shallow marine. The sedimentary facies of Ilam Formation are mainly limestone, and sometimes shaley limestone (in restricted part of the basin). The lack of Coniancian-Turonian sediments in wells drilled in eastern part of the field can be related to erosional phase after Cenomanian-Turonian and developement of paleoheight parallel to Khark-Mish fault. The determined facies are deposited over a carbonate platform (shelf type) in three sedimentary environments: shoal, lagoon and semi restricted lagoon. The petrographic characteristics of detected facies of Ilam Formation revealed that they were experienced different diagenetic realms such as marine, meteoric, and burial and during uplift periods. These sediments then influenced by diagenetic processes such as micritization, compaction, cementation, neomorphism, solution, fracturing and replacement (dolomitization, hematitization, and pyritization). The dominant porosity types are interconnected vugs, fracture and channel which are played a profound effects on the variation of reservoir quality. The measurements of petrophysical parameters present that the averages of porosity, water saturation and net to gross ratio are varied in the Ilam reservoir, but these parameters are generally 2.3%, 88% and 0.016, respectively. In view of low values of porosity, the role of fractures and diagenetic processes are important in the reservoir quality. The paleohigh presence in eastern section is not only affected on facies distribution, but it also has an important role in subsequent evolution. Therefore, the quality of the Ilam reservoir is a function of sedimentation, diagenesis, and tectonic activity; and therefore, it will be variable in different parts.

Shurijeh Formation is deposited in Kopeh Dagh sedimentary basin, and it is one of the gas reservoirs in northeastern Iran. Khangiran gas field with a northwest-southeast structure is located in the northeastern part of Khorasan Razavi province. The purpose of this study is to investigate facies, sedimentary environment and diagenetic processes that have been effective on the reservoir quality of Shurijeh Formation in the studied wells. Based on petrographic studies on thin sections of Shurijeh Formation in the studied wells, nine main rock facies including Sandy Conglomerate, Quartz Arenite, Sublitarnite, Subarcose, Quartz Wackes, Claystone/Shale, Nodular Anhydrite, Sandy Dolomudstone and Sandy Dologrenston have been identified that are located in the tidal, river, flood plain and meandering sedimentary zones. Petrographic studies of thin microscopic sections show that diagenetic processes in three marine, meteoric and burial environments have affected the Shurijeh Formation. The primary processes affected in the facies of Shurijeh Formation include cementation, bioturbation, primary dolomitization and anhydrite. Finally, using image log, petrophysical log and combining the results of thin section studies in the key well of Khangiran field, was determined that in most cases there is a good conformity between the results of image log, thin sections and petrophysical log.

Porosity is a very sensitive parameter for determining the velocity of waves, estimating geomechanical parameters and petrophysical properties of hydrocarbon reservoirs. Today, in oil industry this parameter is obtained by using the helium gas injection method on core samples. Determining porosity by methods such as core analysis requires a lot of time and money. Coring is difficult and costly. In addition, it is not possible to core in some wells (such as horizontal wells). Therefore, due to the lack of sufficient cores and lithological changes and heterogeneity of reservoir rock, the determination of this parameter by conventional methods is not very accurate. So far, many experimental relationships have been proposed to calculate porosity, but in most cases, the results in different regions are not desirable. In this study, in an oil well South-west Iran, porosity was measured using neutron, density and sonic logs and also a combination of these data. Then for 645 specimens of the same section, porosity was measured using helium gas injection test. Correlation analysis and mathematical manipulation resulted in an empirical equation for estimation of porosity based on a combination of three indicators: compressional wave velocity (Vp), density (), and the ratio of compressional to shear wave velocities (Vp/Vs). Artificial intelligence technics were used to optimize this empirical equation. As a result, porosity can be estimated at a lower cost and more accuracy for the whole length of drilling.

Determination of rock types is of special importance in the construction of static and dynamic models of hydrocarbon reservoirs. Estimating the properties of reservoir rocks increases the accuracy in predicting the amount of reservoir storage and its performance. Numerous models have been proposed by experts to determine the types of reservoir rocks. But most of the proposed models are based on conventional methods based on engineering and geology of carbonate reservoir rocks. Therefore, using a machine learning method to determine rock species in comparison with previous methods and comparing its efficiency and performance with other methods seems necessary. In this study, core and log data in maroon oil reservoir after preparation were match using Dynamic Time Series (DTW) technique for depth matching. The brain data were then clustered by the non-supervised machine learning method. The kernel data clustering process was also performed by conventional model-based methods such as flow zone index method (FZI) and Winland. Then, the clustering results were validated and compared with kmeans, FZI and Winland methods by having the lithology information of the logs. The kmeans method with a 93.5% accuracy criterion succeeded in performing the highest cluster resolution, which showed that the kmeans data-based machine learning method is a suitable alternative to conventional model-based methods for clustering rock typing.

Fracture identification is an important step in reservoir modelling and production management. Fractures are among the most important parameters that influence fractured carbonate reservoirs. interpretation of high resolution data such as fullbore formation microimage (FMI) log provide valuable information about distribution and properties of fracturs. The FMI log will also separate closed and open fractures. Obviously open fracture provides ability of fluid movement- permeability- in the reservoir and thus define production ability of the reservoir. However, availability of FMI logs through the whole reservoir is some time a problem while its effective radius is small, too. Thus, integrating fracture modelling with seismic data and FMI log will provide a complete fracture model of the whole reservoir. In this study, we have introduced an integrated strategy for fracture modeling using seismic and FMI data. The strategy was applied on a fractured carbonate reservoir from the Persian Gulf. In the presented strategy, the facture will be identified initially by the FMI log, and then the fracture intensity and cumulative intensity logs were derived. Subsequently by defining zonation area based on fracture intensity cumulative log gradient, primary zonation of the formation reservoir was performed. In this step, fracture model from seismic data was integrated by the upscaled fractures model from well data. Hence, four fracture zone identified in the upper formation reservoir and two in the lower one. Based on this model, one zone from each formation were proposed for further study.

Carbonate formations are typically heterogeneous and anisotropic; hence, dipole sonic logs have great efficiencies in evaluating their geomechanical and petrophysical parameters. In this study, the various uses of DSI logs and processing approaches of its modes are presented as a case study in one of the SW Iranian fields. For this purpose, data from three modes (i.e. 3, 4, and X-dipole) of DSI logs, conventional logs, image log and porosity-permeability core data have been used. Moreover, using the DSI log data, it has been found out that stress state in the studied well is strike slip-normal, and the pore pressure is close to the hydrostatic pressure. In addition, regarding to the wellbore breakouts, the maximum horizontal stress direction is to NE-SW. Moreover, the fast shear wave azimuth is often aligned with the maximum horizontal stress direction. Furthermore, using the DSI log data, energy, traveltime and Dt anisotropies were calculated. The Dt anisotropy increases in fracture and washout zones and traveltime anisotropy which is affected by washouts. In this study, the factors which affect the reflection of the Stoneley waves, and the chevron patterns creation, have been investigated. Also, the most important factor in this case is the wellbore washouts. Finally, it has been found out that the Stoneley permeability has a relatively good correlation with the core permeability.

In naturally fractured reservoirs, hydrocarbon production is mainly depends on permeable fractures. Therefore detecting permeable fractures in reservoir rock is a priority. Generally, there are many methods to detect fractures in reservoirs includes using imaging log, temperature log, mud loss log. Imaging logs are unable to predict if a fracture is permeable or not, therefore It is necessary to use some complementary methods like acoustic methods to detect permeable fractures. In this paper, we analyzed a DSI (Dipole Shear Imager) tool which was taken from one of the hydrocarbon reservoirs in south of Iran. First, by using a commercial software (Geolog), the stoneley wave was separated into direct and reflected parts. Then the reflection coefficient of the stoneley wave calculated in the studied section. It is possible to determine if a fracture from FMI log is permeable or not By comparing it to its reflection coefficient. the Results of this method is promising.

Pore pressure prediction is important in hydrocarbon exploration, production, and drilling activities. The presence of abnormal pressure may cause different problems such as pipe stuck, well blow out, mud loss, and so forth. Using seismic data is the only method for pore pressure prediction before drilling. In the present paper, stacking velocity which has been obtained from 3D seismic data processing was calibrated with acoustic log. The effective pressure was determined using Bower´s equation. Pore pressure would be predicted by overburden pressure and basic Terzaghi´s equation as well as abnormal pressure zones if existed. The results indicated that there have been two abnormal pressure zones existed in the Kupal Oilfield: high pressure zone in Gachsaran Formation (Member 1 or cap rock), in Pabdeh Formation, and two low abnormal pressure zones in the upper part of Asmari Formation. Pore pressure in Lower Asmari section is higher than in the upper part due to higher porosity.

Accurate knowledge of the stratigraphic sequences and their possible discontinuities is so important for the characterization of reservoirs. The purpose of stratigraphic correlation is detecting geological boundaries to construct a three-dimensional model of the reservoir. This process is usually done manually, therefore, depends on interpreter’s experience, multiple interpretation is not unexpected. Using automatic algorithm to detect geological boundaries in addition to facilitating correlation and removing multiple interpretation will lead to save money and time. In this work, Fractal and statistical features are implemented to extract well-logs pattern. Wavelet transform analysis is used to determine fractal dimension. Detection of the pattern in observation well which is similar to the pattern obtained in witness well (a well which depths of all boundaries are available) around the selected boundary is the basis of this novel approach. Automatic Stratigraphic correlation algorithm is implemented on well-logs of 4 wells in one of the oil fields in southwest of Iran. For this purpose, one of the geological boundaries in witness well is selected and the aim is to find the depth of the corresponding boundary in the other wells. The approach was able to detect the depth of the boundary in all the wells. The deviation of the results of the automated approach from the manual ones is about 1.07 meters which confirm effectiveness and capability of this approach.

Mud invasion occurs in permeable formations because of overbalance drilling. During mud invasion, liquid phase of mud invades into formation, and the solid phase accumulates on the borehole wall (mud cake). Rate, volume and geometry of mud invasion are controlled by (1) mud properties, (2) petrophysical properties of formation and (3) pressure difference between mud and reservoir. The invasion of mud severely damages reservoirs and reduces its productivity. In addition, it has negative impact on the acquired data, e.g. wireline logs, formation tester and also rock and fluid sample. Different mathematical and experimental models have been developed to model mud invasion considering different aspects of the problem. Implementing these models in real cases does not have satisfactory results because they need major modifications. In this paper, we adjust mud cake permeability as the main controlling parameter of mud invasion. It is accomplished by inversion of resistivity logs. We developed different workflows using Petrel software to simulate the mud invasion and invert the resistivity log. The objective function of the inversion was the difference between modeled and real resistivity logs. After optimizing the mud cake permeability, the mud invasion profile significantly improved.

Thin layers of sand within clay are capable of producing hydrocarbons in the case of being carefully analyzed. These layers are often ignored because of their low thickness and low resolution of common reservoir petrophysical evaluation logging tools in conventional methods. These tools only calculate the average properties of these layers which make a wrong prediction of amount of oil and gas in layers. There are some methods for better analysis of the layers and increasing the production of reservoir which can accurately identify thin laminated shaly sand and calculated petrophysical parameters with high precision. In this paper, laminated shaly sand layers (LSS) are studied by using Thomas Stieber model and common reservoir petrophysical evaluation logs. Thomas Stieber model is applied to the desired layer by laminated shaly sand analysis module in Geolog 7.2 software, and the results of this model and the common reservoir petrophysical evaluation logs were analyzed by using this software. According to the results of the Thomas Stieber and conventional logs’ analyses without implementing shear cut-offs, the amount of the porosity increased 6.5 % and 5.4 % for well A and B, respectively. Also, the amount of the water saturation for well A and B decreased 38.8 % and 16.3 %, respectively. Finally, by comparing the results of the analysis, it was concluded that Thomas Stieber model calculates properties of laminated shaly sand layers more accurate than the common reservoir petrophysical evaluation logs and this model can be used to study these sequences.

Using of well logs in un-cored wells in order to identify rock strata related features usually has been discussed between the geologists. In this study, firstly, based on drilling cores, depositional sequences and surfaces of the Permo-Triassic successions in the Persian Gulf and Coastal Fars areas are identified. Then, using processed gamma and density well logs (wavelet analysis), in Cyclolog software, sequence stratigraphic surfaces including sequence boundary and maximum flooding surfaces are recognized and compared with the petrographical results. The recognized surfaces based on gamma ray logs are more compatible with the identified surfaces based on depositional facies, than results of density well logs. According to decreasing and increasing trends and turning points on the processed gamma ray and density well logs of the studied wells and fields, several (isochronous) correlatable surfaces are recognized. Rather than gamma ray and density well logs, Sonic, Neutron, Potassium, Thorium, spectral gamma ray and resistivity, are analyzed using wavelet method which gamma, Potassium, Thorium and Neutron well logs show same results.

Core testing is the most accurate and most expensive method of measuring permeability. A lot of effort has been carried out for finding alternative methods to estimate permeability. One of the indirect methods of estimating permeability is using Stoneley waves. The main advantage of this method is to record Stoneley waves intrinsic property affected by the permeability and by quantifying the relationship between the physical parameters of waves and permeability, a continuous log of permeability changes around the wellbore can be prepared. This method results are influenced by many parameters; such as, porosity,lithology, accuracy of permeability measurement done by core or MDT tools and calculated Sotoneley slowness in rock matrix. In this study, the effects of the above parameters in the calculation of quantitative values of permeability have been studied. Based on the results, the parameters of porosity and slowness of Stoneley wave in rock matrix have more influence on accuracy of determining permeability. The observation shows that by absence of the accuracy in calculation of Stoneley slowness in rock matrix, the permeability values of some points will be negative. In addition when the porosity parameters is used in permeability , the results are more in tune with permeability values derived from the MDT tools.

The purpose of this study is to calculate and investigate the effect of porosity on the elastic moduli in Kangan and Dalan Formations in the South Pars gas field of Iran. Compressional and shear wave velocities were calculated using travel times of compressional wave and travel times of shear waves, which are deduced from the Dipole Shear Sonic Imager (DSI) logs. Bulk modulus, Shear modulus, Young’s modulus, Lame parameter, Poisson’s ratio and the ratio of K/G were calculated using the relationship between the acoustic wave velocities, density and physical moduli. In this study, the relationship between porosity and elastic moduli were determined by real data and observed that elastic moduli are decreased by porosity increasing. Comparison of elastic moduli with porosity shows significant consistency between bulk modulus and porosity (compared to other moduli). Also, the ratios of Vp/Vs, K/G and Poisson’s ratio were examined. Result of this investigation showed that these ratios are slightly reduced by increasing the porosity.