IRANIAN JOURNAL OF PETROLEUM GEOLOGY
Year:2013 | Volume:3 | Issue:5|Papers Count:6

Secondary and Tertiary recovery processes can lead to severe and permanent reductions in permeability due to the interactions between injected fluids and the reservoir rock that is especially true in high clay content, low permeability, poorly consolidated reservoirs. After the fluid with a high pH value enters the reservoir, the texture of clay minerals and siliceous cement in the reservoir is destroyed due to the dissolution of clay minerals and cement and the release of fine particles produced, thus causing reservoir plugging. Formation damage could be both temporarily due to the precipitation of reaction products caused by interaction between high pH fluids and reservoir rock which will result in pore plugging. In this study, a series of core flooding experiments have been carried out to determine the critical pH of Alkaline fluids for plug samples of Fahlyian carbonate formation. Alkaline fluids with different pH (7, 8.5, 10 and 12) were injected into plug samples and the alkaline sensitivity of the carbonate formation has been measured in both qualitative and quantitative forms by a new applicable method. Using this approach will result in the accurate estimation of the degree of formation damage. Results indicate that used plugs show different behavior when exposed to fluids with different alkalinity and the degree of resulted formation damage varies from zero to serious and in certain cases are noticeable and Irreversible. Therefore, pH of injecting fluids must be kept less than its threshold value to prevent formation damage.

Reconnaissance and interpretation of underground heterogeneity, particularly litho-facies, always plays an important role in evaluation and management of hydrocarbon resources. Between various methods presented for modeling discrete characteristics of hydrocarbon reservoirs such as litho-facies, one with a more proper conformity with actual condition of reservoir facies is of great advantage. Formed on basis of probability and presenting transition matrix, Markov method is widely applied as a powerful tool for modeling the facies. In the present study, first the method is introduced in details; then, in order to optimize it, suggestion is made based on changing the type of the move of chain in simulation procedure. The case study is a 12 km long 110 m thick section of Anhydrite and three major members of Asmari Formation from an oil field, South-West Iran. This section is modeled through Markov procedure and proposed solution. The models set indicated that on basis of using the data from two wells and five seismic horizons, best result, with 90% accuracy, is for reciprocating motion.

Reservoir lithology determination is one of the main studies used for well correlation and analyzing productive zones of the reservoir. The best way for lithology determination is using core and cutting information. Nevertheless, in most wells these data is not complete and continual, so in these cases usually use well logging for lithology estimation. The purpose of this paper is representing accurate method for lithology estimation of petrophysical well data with Clustering-Estimation approach. This method has been generalized according to one well from one of the oil fields in South of Iran that contains core data. Then this method is generalized in uncored wells. Clustering is used as a way for grouping well data in homogeneous lithology clusters Afterward, percentage of mineral is estimated in each of these clusters. The regression coefficients are calculated 92.93% and 74.99% between real and estimated data respectively for calcite and dolomite in one of the wells. The results with high accuracy show the generalization of this method.

Survey and study of porosity and the form and the size of that in oil and gas reservoirs are important due to its key role in reservoir quality and productivity. In this paper, unlike conventional methods of using cores to recognize the geometry and morphology of porosity, FMS image log and thin sections of cuttings from drilling are used. After determining the overall dimension of the porosity shown as black patches and spots by FMS log, the shape and the size of the porosity was studied in the form of petrological study, based on thin sections from Mozdouran reservoir formation(lower Jurassic) in one of the gas fields in the East of Kopedagh basin. Tracing and comparing of the results of the two methods show a good correlation for determining the type and geometry of porosity. Data fusion of FMS log data with petrological studies of thin sections of cuttings from drilling has advantages the most important of which is the possibility of replacement of core with FMS log and thin sections in order to determining the geometry of porosity.

The hydrocarbon seepages theory puts forward a cause and effect relationship between the oil and gas reservoirs and the specific surface anomalies which are basically related to hydrocarbon leakages as well as their related alterations. Hence, the spectral reflectance of the hydrocarbons and their linked mineral alterations produce credible pieces of evidence for oil and gas exploration. Hyperion images of EO-1satellite was used in this study for identifying the oil seepages and their relevant alterations. After collecting the required data, the images underwent the needed preprocessing. In order to recognize the oil seepages, these corrected data along with field-sampled spectrometric ones were employed. Then, VISA and SCM combined model was applied to indirectly identify the hydrocarbon seepages. Moreover, two hydrocarbon indexes were developed for direct recognition of the hydrocarbon seeps using Hyperion images. The findings indicate that the two mentioned techniques are efficacious for the purpose of the study at hand.

There are two key methods of simulating multi-phase flow experiments. One is the actual estimation of multi-phase flow properties from measured data, and the other is the representation of the analytical functions for relative permeability and capillary pressure. It is essential that these functions have sufficient degrees of freedom to model the measured data whilst remaining straightforward and easy to communicate. A new smooth and flexible three-parameter analytical correlation for relative permeability is proposed. Results from e.g. unsteady state relative permeability experiments often exhibit behavior which is difficult to model using e.g. Corey correlation. The new correlation influences different parts of the relative permeability curve and thereby captures variable behavior across the entire saturation range. The validity of new correlation is demonstrated by utilizing unsteady-state experiments performed at ambient conditions on core samples from the Southern Iranian reservoir rocks. Results show that there is a logical relation between the basic rock properties and tuning parameters of new correlation. For the modeling of the relative permeability, the relation of tuning parameters against basic parameters, i.e. permeability and porosity, should be found. Knowing the logical correlation and the basic parameters from routine analysis or logs, the tuning parameters and therefore relative permeability curves will be easily calculated.