Porosity estimation is a critical challenge in carbonate reservoir characterization due to complex pore systems and heterogeneity. This study compares core-derived and log-calculated porosity measurements in a carbonate reservoir in Southwest Iran at depths of 3250–3750 m, addressing industry challenges of data reliability and cost efficiency. While core analysis yields direct porosity measurements, its high cost and limited spatial coverage necessitate reliable log-based alternatives. The research utilized neutron, density, and acoustic logs to calculate porosity through established petrophysical relationships, comparing results with core data from 648 samples. Two innovative zoning approaches were developed: depth- and lithology-based zoning identified five distinct reservoir intervals, while porosity-based zoning classified the reservoir into three quality classes. Results show strong agreement between methods; log-derived mean porosity of 15 % closely matches the core measurement average of 12 %. Neutron-density logs effectively capture total porosity, while acoustic logs indicate primary porosity, enabling secondary porosity quantification. A key achievement is the implementation of Geolog software's deterministic and probabilistic methods to minimize interpretation subjectivity, reducing reliance on extensive coring while maintaining accuracy. The depth-based zoning approach identified high-quality reservoir intervals between 3450 and 3550 m with porosity exceeding 20 %. This work advances previous studies by offering: (1) a validated protocol for log-core integration in heterogeneous carbonates, (2) quantitative assessment of secondary porosity, and (3) practical zoning methodologies for reservoir quality prediction. Future research should focus on machine learning (ML) applications to enhance porosity prediction models and integrate advanced logging tools for improved fracture porosity characterization.

Determination of reservoir rock types is an important and necessary task for reservoir development and production. Fluid production from complex carbonate reservoirs that have undergone diagenetic processes, necessitates a thorough and reliable assessment of the reservoir characteristics. Since core samples from hydrocarbon reservoirs are not always available, nuclear magnetic resonance (NMR) and conventional well logs, or a combination of other methods are usually used as alternatives to estimate petrophysical properties. This study examines a giant carbonate reservoir of Asmari Formation (depth interval of 2513.5–2674.8 m) in the Dezful Embayment, southwest Iran. NMR and conventional well-log data together with multi-resolution graph-based clustering (MRGC) methods were used to determine the rock types based on electrofacies and flow zonation indicator (FZI). Porosity (φ) and permeability (K) were derived from the NMR data using the Schlumberger-Doll-Research (SDR) and Timur-Coats methods. The estimated core-derived porosity and permeability data were used to classify six distinct FZI groups and associated rock types. The conventional well logs were exposed to MRGC algorithm to distinguish five electrofacies-based clusters. The results of the FZI and MRGC methods were then compared and reconciled to determine consistent rock types. The analysis reveals that rock type R1 determined by the FZI method displays the highest quality reservoir with FZI > 4.896 and reservoir quality index (RQI) > 0.852. Applying the MRGC method using just two NMR-derived variables resulted in six rock-type clusters. Rock type R1 displays a total combinable magnetic resonance porosity ( T_cmr ) of 0.13 and a logarithmic mean of T2 distribution ( T_2lm) of 440.33, identifying it as the rock type with the best reservoir quality. Evaluating NMR and conventional well-log data with MRGC results provides a comprehensive and reliable classification of the reservoir rock types and assessing their reservoir quality, providing an alternative scheme based on NMR-FZI rock-type analysis.

Long-time contact of heavy crude oil with rock leads to an adsorption phenomenon, which causes the rock surface to become oil-wet and appears as a barrier to the fluid flow in the porous media. However precise understanding of how asphaltene fractions influence sand wettability is lacking. The wetness of neat and asphaltene-aged sandstone was calculated using two relative permeability and contact angle methods. Then the molecular interaction between asphaltene and sand minerals was systematically analyzed using Fourier-transform infrared spectroscopy. Furthermore, the zeta potential was representative of electrostatic properties and surface charge alteration of the sand after these phenomena. Scanning electron microscopy with energy-dispersive X-ray (EDX) analysis also showed elemental mapping and dispersion of asphaltene particles on the rock surface. According to contact angle and EDX analyses of asphaltene samples, the contact angle rises from 115° to 141° by an increase in carbon adsorption on the sand surface from 8.23 to 41.56%. Spectroscopy results demonstrated that hydrogen-bonding, π-bonding, and sulfur-containing compounds such as sulfoxide improve asphaltene adsorption onto the sand surface. The higher the aromaticity index and hydrogen potential index of asphaltene, the greater the ability of asphaltene to change wettability. Adsorption of surface active components would make the surface charge of the sand more negative. The presence of nitrogen/sulfur-containing functional groups on the sand surface changed the electrostatic properties, as a sand surface coated with asphaltene would reduce the percentage of metal cations.

The process of smart water injection into carbonate reservoirs has always faced many challenges. This study attempted to investigate this issue by examining two effective factors active ionic compounds in brine and active compounds in the oil phase. The potential for the reaction among three phases’ oil, rock, and brine in changing wettability requires the presence of active ionic compounds in the brine water and active compounds in the oil. These compounds in optimal concentrations are the driving force of the wettability alteration process. In the first step, the contact angle and the spontaneous imbibition process were performed on the outcrop samples and the limestone core to investigate the effect of the active compounds of smart water. The efficiency of calcium and divalent magnesium cations mainly depends on the sulfate ion concentration. However, reservoir physical condition and the presence of other effective compounds in the reactions network can be helpful in the determination of the essential active ions in the reaction. Finally, the optimal concentrations of these three ions lead to the formation of a stable water film and a change in the wettability of the rock, which leads to an increase in oil recovery. In this regard, cations in the presence of sulfate ions as much as the minimum concentration in seawater can have a positive function and have an acceptable efficiency compared to increased concentrations of sulfate ions in seawater. The cores were saturated with two oil samples for further investigation, and again, two tests of measuring contact angle and spontaneous imbibition were performed. The difference between imbibition rate and ultimate recovery illustrates that the carboxylic acid functional group in the original crude oil structure can facilitate displacement compared to oil-free acid components. Therefore, acidic components in crude oil affect the wettability alteration through electrostatic interaction with surface minerals and brine. Active components can act as a critical indicator in smart water injection processes.

Summary One of the fundamental parameters in the fluid flow in porous media is the rock-fluid interaction that affects the wettability and fluid flow pattern. In this study, three crude oil samples from an oilfield of southwest Iran were selected to investigate the bonds and interaction between oil and calcite reservoir rock. The results of relative permeability and contact angle measured for each sample demonstrate that residual oil saturation and oil spread over the rock surface are different for each oil sample. According to the results of Fourier transform infrared (FTIR), the oil sample with higher intensity of O-H stretch band on the rock surface raises the interaction and bonding and shifts the rock towards oil-wetting. In addition, the presence of aromatics with high concentration in oil samples and the existing bonds on rock indicates the high importance of these compounds in oil adsorption on reservoir rock surface. Moreover, the relatively polar S-H stretch bonds have a slight impact on oil adsorption and create a weak bond with the rock surface. Based on the results of this study, the potential of bonding and rockfluid interaction in porous media to be estimated in terms of wettability alteration and fluid flow regime.

Fractured reservoirs are important hydrocarbon resources. However, the production of hydrocarbon makes fractures to be sealed which in turn decreases the production rate. A better understanding of permeability, porosity, and compressibility of fractures would be useful in optimizing the production rate. This research paper explored stress-dependent permeability, porosity, and compressibility of fractured porous media, both experimentally and numerically. The laboratory results are used to calibrate numerical models. With this regard, the roles of fracturing parameters such as orientation, opening, fracture density, persistency, and the intersection of fractures on hydro-mechanical parameters of the fractured sample are analyzed individually. The results indicate that stress sensitivity of permeability and compressibility is more in fractured porous media than in non-fractured ones. The results gained also showed that samples with open fractures and no filling materials, dominant vertical fractures, and high fracture density have the most stress dependency of permeability and compressibility, while in high fracture densities, the fracture and matrix changes are close to each other. The intersection of joints and not persisted fractures act as obstacles. This causes the fluid to be trapped in porous media that affect reservoir recovery and increase financial losses. Finally, an analytical relationship is developed to calculate the matrix compressibility

Although fractured reservoirs are important hydrocarbon resources, the increase in effective stress due to production causes fractures to be sealed and hence production rates decrease. A better understanding of permeability, porosity, and compressibility of fractures would be useful in optimizing production. This research paper describes experiments on carbonate fractured reservoir rocks by measuring the permeability, porosity, and compressibility of different types of fractures, based on their orientation, opening, density, and persistency. Fractured cylindrical rock samples from a south Iran oil reservoir were tested by helium gas apparatus in hydrostatic condition. Microscopic X-ray computerized tomography (CT) scanning was utilized to show fracture distribution and the network. The experimental results indicated that stress sensitivity of porosity in fractured rock is lower than that of permeability and compressibility. Different analytical models were applied to describe permeability, porosity, and compressibility with respect to effective stress. The analysis showed that the permeability and compressibility of fractured reservoirs are more dependent upon the orientation, opening, density, and persistency of fractures.

Three modes will improve the interaction of the wax-asphaltene molecules that eventually increase wax appearance temperature (WAT) within crude oil. The first mode takes place when the wax is composed of long-chain alkanes, and its aromatic compounds are low, and adjacent hydrogens in its constituent aromatic rings are substituted with long-chain paraffin. The second condition is when the wax is formed from low carbon number alkanes. In this case, the lower the asphaltene aromaticity and the carbon number of side alkyl chain, the higher its interaction with wax would be. The third approach occurs if naphthenic or aromatic structures exist in wax, and asphaltene aromatic rings are arranged as peri-condenses. Higher interaction of wax and asphaltene reduces wax crystals’ size. The presence of polar compounds in the molecular structure of the wax and asphaltene does not affect WAT, but the size and morphology of crystals alter in microscopic images.

Summary Inorganic scales are one of the most common flow assurance challenges damaging well productivity and decreasing injectivity in oil and gas reservoirs by reducing permeability. In this study, the effect of ultrasonic waves on the removal of potassium chloride from carbonate reservoir rock is investigated using a modified coreflooding apparatus equipped with ultrasonic. According to results, ultrasonic waves improved permeability by methanol injection from 36% to 76%. The mechanical effects of these waves on KCl crystals in porous media increase the temperature 20 °c, cracking the crystals and reducing the binding force between crystals and rock surface. The scanning electron microscopy (SEM) images illustrate that ultrasonic waves broke the strong and continuous structures of KCl crystals in porous media. These factors increase the solubility of these sediments with methanol and restore the permeability. Based on the results of this study, ultrasonic waves can be used as a novel technology in the removal of mineral deposits, especially in gas wells, because these waves have high efficiency in the removal of inorganic scales and also reduces the environmental impact of using solvents.

Application of light-weight drilling fluids is essential to develop depleted hydrocarbon reservoirs. Recently, colloidal gas aphron (CGA)-based fluids have been introduced for such applications due to their ability in controlling fluid losses. In this work, a comprehensive experimental study was performed to choose the best formulation for CGA fluids by implementing static stability tests, rheological behavior measurements, and bubble size analyses of CGAs. Xanthan gum polymer and sodium dodecyl benzene sulfonate (SDBS), an anionic surfactant, and cetyl trimethyl ammonium bromide (CTAB), a cationic surfactant, were utilized to prepare CGAs. For the range of experiments conducted, the performance of CGA fluids prepared with SDBS was improved by increasing the polymer and surfactant concentrations. However, for CTAB, it was improved by an increase in the polymer concentration and a decrease in the surfactant concentration. The formation of white, long hair-like precipitates observed at high levels of CTAB caused CGA fluid to become rapidly unstable. Also, it was observed that the size of CGAs was significantly influenced by the polymer and surfactant concentrations. The most stable bubbles were formed at 6.86 g/L of polymer concentration. The results of this study provide insights into appropriate formulation for CGA-based fluids which could be potentially applicable in drilling operations.

Defining the depth of gas-oil contact (GOC) is essential for the volumetric and detailed petrophysical calculations. Variations in the entropy of pore fluids can serve as a diagnostic criterion for determining the interface between oil and gas phases. Inherently endowed with a high resolution of pore fluids, nuclear magnetic resonance (NMR) data is a highly promising candidate for extracting the entropy of pore fluids. As a paramount technique in extracting the hidden and significant temporal features of the original data, wavelet analysis can viably reveal the information of pore fluids encoded in the NMR log data and express it in terms of entropy. In this research, the discrete wavelet transform (DWT) was first employed to derive hydrocarbon relaxation time (TH) from the NMR echo signals in the reservoirs under study. The variations of TH reflected on the various decomposition resolution levels were then used to calculate the entropy of hydrocarbon fluids (EH) at each depth. Finally, by scrutinizing the entropy variations, the gas-oil contact in each reservoir was accurately determined. The depth of the gas-oil contact ascertained from the wavelet-based approach corresponds precisely to that determined from the conventional method of the neutron-density cross-plot.

Recently, Colloidal Gas Aphron (CGA) based fluids have been introduced to further develop depleted hydrocarbon reservoirs. This fluid system has been employed in an attempt to control drilling fluid invasion and, thus, reducing formation damage occurred during drilling operations. Understanding the mechanisms of fluid invasion control is of great importance for successful design and application of CGA-based fluids in drilling operations. Although fluid flow of conventional foams has been studied extensively in the available literature, little attention has been paid to CGA fluids flow, especially in heterogeneous fractured porous media. Here, an experimental study was conducted to achieve maximum knowledge of CGAs blocking mechanisms in heterogeneous unfractured/fractured porous media using a micromodel setup. Fluid invasion control was studied with the aids of direct observations, injection pressure of CGA fluids, and return permeability calculations. Microscopic mechanisms such as bubbly flow, trapping of CGAs, aggregations of bubbles within fracture, and configuration of different phases were observed in the experiments. Observations revealed that CGA fluids reduce fluid invasion through creation of nonbonding aggregation of CGAs in the fracture. Injection pressure data of CGA fluids were employed to compare performance of two CGA fluid samples prepared by Sodium Dodecyl Sulfate (SDS) and Sodium Dodecyl Benzene Sulfonate (SDBS) surfactants. Results showed that CGA sample prepared by SDBS provides a better fluid invasion control capability, possibly due to its wider bubble size distribution compared to that of CGA sample prepared by SDS surfactant. Furthermore, during production phase, CGAs were easily removed by produced oil, and a higher return permeability (about 80%) was achieved for CGA fluids prepared by SDBS. Finally it has been shown that aqueous CGA fluids perform better in oil wet conditions than in water-wet conditions. This study provides a helpful reference for understanding blockage ability of CGA fluids occurred in drilling operations.

Identification of pay zones is as a challenging topic in the reservoir characterization. Various methods have been employed to tackle this prominent task. Well logs are one of the most useful means for identifying pay zones, chiefly resistivity logs. However, resistivity measurements in some complex environments such as mixed lithology reservoirs, low resistivity and low contrast pay zones may fail to unveil productive zones. As an essentially lithology-independent tool, nuclear magnetic resonance (NMR) log may be the only approach to deal with detecting such subtleties. Using wavelet analysis technique and the NMR log data, this paper was aimed at identifying hydrocarbon bearing zones in two carbonate reservoirs. Discrete wavelet transform (DWT) was applied to the spin echo train at each depth to extract transverse relaxation time (T-2). By comparing the generated T(2 )log and resistivity log, a striking similarity was found between them. The T-2 log manifested strong correlation with porosity log. Therefore, the DWT was repeatedly applied to the T-2 log so as to remove the correlation. Various wavelets were adopted to remove the effect of porosity from the T-2 log, leading to achieve pore fluid transverse relaxation time, referred to as T(2f )Scrutinizing the T-2f log demonstrated that this log is not only highly functional in detecting productive zones but also highly capable of highlighting the subtle changes of pay zones. Consequently, the T-2f log revealed the latent pay zones unseen by resistivity log.

To examine the effect of pressure on pore structure and petrophysical properties of carbonate rock, the porosity, permeability, CT scanning, SEM and elastic wave velocity of two carbonate core plug samples from an oilfield in Southwest Iran were analyzed under cyclic pressure. One of the plugs was calcite and the other was dolomite with anhydrite nodules. The cyclic pressure exerted on the samples increased from 13.79 MPa to 27.58 MPa in six steps, and the variations in petrophysical properties of the two samples at different pressure loading and unloading steps were counted and analyzed. The results show that the calcite sample decreases in porosity and permeability with the increase of pressure, which is consistent with the results from compression and shear wave velocity tests. In the dolomite sample, the decreasing trend was not observed; fluctuations of compressive and shear velocities were observed during the loading stage, which may be due to different geometries of the pores and the porosity variation in the sample. Understanding the variation of carbonate petrophysical properties with pressure is helpful for optimizing reservoir development scheme.

This study investigates the properties of asphaltene fractions in porous media and their role in reducing permeability and porosity. Based on the classification of a whole asphaltene deposited in porous media, the fractions can be defined as bulk, hard (h)-adsorbed, normal (n)-adsorbed, and irreversible (i)-adsorbed, which effects on porosity and permeability reduction in the reservoir rock. According to laboratory results for five types of calcite cores with porosity and permeability close to each other, the highest reduction in porosity (55%) and permeability (76%) is related to bulk asphaltene fractions. The n-adsorbed and h-adsorbed asphaltenes have approximately equal influence in reducing the porosity and permeability values in the reservoir rock. The i-adsorbed asphaltene, which has the highest adsorption on the rock surface, has the lowest porosity and permeability decrease due to lower amounts of asphaltene deposits in porous media. The amounts of hydrogen (H), nitrogen (N), sulfur (S), and oxygen (O) are higher in adsorbed fractions of asphaltene. In the case of hadsorbed asphaltene, H has the highest value in the asphaltene fractions (7.13 wt%). Compared with adsorbed asphaltene fractions, N values are higher in n-adsorbed (1.89 wt%) than h-adsorbed (1.41 wt%) fractions. This suggests that the S element plays a more significant role in the adsorption of asphaltene to the calcite surface. Based on the results, asphaltene compounds that adhere to the rock surface contain lighter carbon compounds than whole asphaltene. This means that the peak of the carbon compounds of h-adsorbed asphaltene in each rock sample is C-17. Fourier-transform infrared spectroscopy (FTIR) results show that the highest concentrations of carbonyl, carboxylic acid or derivative groups are found in h-adsorbed and n-adsorbed asphaltenes, respectively. A new experimental model of asphaltene deposition has been presented based on the deposition analysis of each asphaltene fraction in a porous medium under dynamic conditions, which results in a high correlation coefficient for each of the asphaltene classifications in the porosity and permeability reduction model. The reason for the high accuracy and uniqueness of the model is the use of parameters such as the velocity of fluid flow in the pores and the amount of volume injected in the reservoir rock sample, as well as the asphaltene fractions and their polarization ratio.

The petrophysical properties of carbonate reservoirs may change when they are subjected to mechanical loadings due to the softness of the formation. As the reservoir fluid pressure declines due to production, the net load on the rock increases, which leads to compaction of the rock and decrease in its pore volume, causing blocking of pore throats and the permeability reduction. In this study, we experimentally investigated the hysteresis effect of petrophysical properties of two carbonate core samples during the loading using CMS-300 apparatus. The structure of samples was processed by CT scan images and analysis of the pore size distribution was also conducted using mercury injection testing followed by scanning electron microcopy (SEM). Our results indicate that isotropic long-term and short-term loading considerably change the grain structure, while the petrophysical properties do not have a clear effect. The porosity induced by the cyclic loading was affected by intergranular micro-extension fractures. The results also indicate that the greatest reduction of porosity in fractured limestone occurred at the first loading step; however, further reduction was strongly due to the consolidation and adherence of the grain matrix. This fluctuating trend was also observed for the permeability, with a severe reduction in the permeability when crushed grains were placed in the connected pore path. The measured porosity and permeability of carbonated rocks, as stress-sensitive parameters, along analysis of the micro-fracture effects during loading and unloading, can be considered in production and injection management of reservoirs. They are also useful for predicting of any possible risks during different periods of reservoir life and determining the optimum production pressure of the reservoir.

Summary This study investigated the effect of average carbon number and molecular/bonding characteristics of wax on wax appearance temperature (WAT) and wax crystal shape under microscope. Three samples of SAR, AS, and FAH from oil fields in southwestern Iran were analyzed. Their WAT values were measured using cross-polarized microscopy (CPM). The results showed that the average carbon number of the wax samples was in direct relation to WAT, with WAT increasing proportionately with increases in the average carbon number. The SAR sample with the highest average carbon number among the three samples showed a higher WAT than the other two. According to FTIR results, SAR and AS samples in their molecular structure, in addition to paraffinic compounds, slightly contain polar/naphthenic compounds. The presence of these structures in the wax molecule affected the interactions between the molecules of the wax and the interactions between the wax-asphaltene molecules, and increased the WAT. At 30oC below the WAT point, images taken from surface the oil samples were subjected to image processing. The SAR sample, which had the highest average carbon number, formed small, rod-shaped crystals, while the FAH sample with smallest average carbon number formed large, round crystals.

Summary One of the top concerns for numerical simulation of naturally fractured reservoirs is fractures’ distribution and properties throughout the reservoir; However, most of the times this kind of information is absent between reservoir data. Due to this lack of data, the production rate and pressure in numerical simulation of fractured reservoirs usually could not consistently and accurately match with the reservoir’s actual observed data. In this study it’s tried to find some specific patterns for fractures’ network in a real Case study of an Iranian oil field. Although the fractures may have considerable porosity and permeability, the network of fractures may not continued in the reservoir layers but are concentrated in some specific area such as beside major faults. By this assumption, fractures which are created by faults, the fracture properties have been defined by considering the orientation of faults and getting a decreasing trend from faults toward the reservoir flanks. For this purpose some correlations are developed for fracture porosity, permeability and shape factor, whether the grid block is modeled as single porosity or dual porosity. The application of this method could improve the numerical simulation history matching of reservoir clearly in a famous Iranian fractured reservoir.

In this study, the effect of the molecular and structural wax properties of five oil samples from reservoirs in southwest Iran on the wax appearance temperature (WAT), shape, and morphology of wax crystals was investigated. After determining the WAT by cross-polarized microscopy (CPM) and viscometer, the wax was subjected to Fourier transform infrared (FTIR) spectroscopy analysis to determine the intermolecular bonds and structure of the molecules. The results show that there is a close relationship between the shape and size of the wax particle and the intensity and types of peaks in the FTIR spectrum of the wax. Paraffinic wax samples had rounded crystals of varying sizes, while polar/naphthenic compounds formed needle-shaped crystals. In the wax structure of some crude-oil samples, although normal alkanes are the main component of the wax, polar and naphthenic structures, albeit small, can also exist. The experiments showed that polar compounds also existed in the naphthenic wax sample, although the paraffin wax sample contained no polar/naphthenic compounds. The presence of asphaltene in crude oil and in polar/naphthenic wax samples affected the WAT and the crystalline form. As the amount of asphaltene increased, the interaction between the polar/naphthenic wax and asphaltene molecules increased; consequently, the WAT also increased. Energy-dispersive spectroscopy (EDS) analysis showed that as the wax sample loses its hydrocarbon nature, its carbon content decreases, and changes in the SNO elements in the wax structure occur, the WAT proportionally increases. Scanning electron microscopy (SEM) images of wax samples showed that semi-microcrystalline samples were composed of rounded and compacted grains; however, paraffinic waxes consisted of a network of large tubular crystals similar in shape to rice grains. The presence of polar/naphthenic compounds in the wax structure changed the shape and density of particles, as shown in SEM images. The dispersion, mean size, and shape of the wax particles, both under the polarized light microscope and under SEM, depend on the molecular/bonding structure of the wax, the elemental composition, and the amount of asphaltene.