Iranian Journal of Oil and Gas Science and Technology

Abstract Among the different operating parameters that must be carefully controlled during the drilling operation, penetration of drilling mud into the permeable zone of formations is one of the essential ones that can have a destructive effect on the productive zone. Thus, the current investigation concentrates on investigating the effects of different nanoparticles (NPs), namely SiO₂, CuO, and ZnO, considering their size, type, and concentration (0.2 to 2 wt % for each nanoparticle) on the properties of the drilling fluid, including rheology and high- and low-temperature filtration. NPs can improve the rheological properties of the mud by changing the friction coefficient favorably. Moreover, the effects of temperature and pressure as two critical thermodynamic parameters are examined. The results show that it is possible to enhance the rheological properties (viscosity) of the drilling mud to a maximum value of about 20 % if NPs with a concentration of 2 wt % are added to the drilling fluid. Extreme gel strength will lead to high pump initiation pressure to break circulation after the mud is in a static condition for some time. The results reveal that reducing the gelation properties of the drilling mud is possible using low concentrations of NPs. Moreover, the results reveal that SiO₂ and ZnO exhibit a lower filtration rate than CuO. Finally, the effects of temperature and pressure were investigated, which revealed that regardless of the reductive effect of NPs (reducing the filtration rate from 17.7 to about 10 cm³), increasing the pressure and temperature lead to an increase in the filtration rate (reducing the filtration rate from 67 to 35 cm³). Further, the rheological properties of the mud remain relatively constant.

Abstract Every day, a large amount of gas is consumed and transported through pipelines. Due to the irreparable consequences of the gas-related accident and their heavy financial losses, despite the company’s mission in the field, such as increasing the gas supply coverage, increasing customer satisfaction, and predicting emergency response plans, the safety of pipelines is one of the priorities of gas companies, government, and consumers. Hazard is part of every human endeavor, so hazard identification and risk management are critical. As some events may not be precisely predictable, the study of risk is critical. Risk management is a determinative step of the health, safety, and environmental management system (HSEMS). This study evaluates the performance of hazard and operability (HAZOP) analysis to assess hazards and risks for all processes present in Kermanshah Province Gas Company. Different risk analysis techniques include FMEA, JSA, and HAZID. As the HAZOP is a process hazard analysis that not only identifies system hazards but also determines their probability of occurrence by the effects of any deviations from design conditions and gives us accurate results, it is used for risk assessment in this project. This research is conducted by a team of three experts and identifies the process hazards by employing quid words. At the end of this study in Kermanshah Province Gas Company, about 282 risks are identified, only 03 risks are unacceptable, and 111 are conditional risks that must be eliminated without delay. The others are acceptable risks that must be eliminated but are not emergent.

Abstract The asphaltene and metal naphthenate components of crude oil samples from 10 wells within an oil reservoir were determined using different analytical techniques. The asphaltene content of the crude was determined by gravimetric analyses using American Standard for Testing and Material (ASTMD) 6560 to obtain its weight concentration. In contrast, the metal naphthenate components were determined by obtaining the metal ion concentration of the produced water and the naphthenic acid concentration of the crude using atomic absorption spectrometer (AAS) and potentiometric titration respectively. The results show that the asphaltene content of the crude samples ranges from 2.0000 to 8.000 wt %, while the naphthenic acid concentration indicated by the total acid number (TAN) ranges from 0.3000 to 1.4600 mg/KOH/g. All the crude samples possess asphaltene components and the propensity to form calcium and sodium naphthenate scale deposits with a Ca₂⁺ concentration between 32.5000 and 94.5000 mg/L and an Na⁺ concentration between 27.7 and 105.1 mg/L respectively. However, the formation of naphthenate scale deposits highly depends on the pH of the produced water of the crude, which makes well FT01 less likely to form naphthenate scales since it has a pH of less than 6; in other words, the produced water pH and availability of cations play an essential role in the formation of naphthenate scales. Calcium naphthenate scale formation is more favored at a brine pH higher than 6, while sodium scale formation is favored at a pH of approximately 8.5. An increase in produced water pH during crude oil production is usually caused by depressurization and CO₂ release. Both asphaltene and naphthenate deposits are directly proportional to the specific gravity of the crude and inversely proportional to the API gravity, implying that both components reduce the quality of the crude. Asphaltene and metal naphthenate solid deposits in the crude can cause many flow assurance difficulties, such as blocking expedition lines, pore plugging, wettability, crude oil parameter alteration, and reduction in oil recovery.

Abstract One of the most important methods for enhancing oil recovery in reservoirs is chemical flooding. The performance and efficiency of these processes in increasing oil recovery depend on several factors, including the rock and fluid properties of the reservoir. Therefore, a critical step in evaluating the effectiveness of these methods is conducting laboratory studies and calculating the potential of chemical agents to recover oil. Optimal design, using new approaches such as novel chemical agents or comprehensive studies of chemical flooding at the core scale, is essential to make chemical flooding more cost-effective.
For this purpose, a laboratory study combined with integrated simulation was performed to identify the effective mechanisms in low-salinity water–polymer injection and to determine the necessary and dominant conditions for improving recovery in Iranian carbonate reservoirs. Initially, four injection scenarios were tested in the laboratory: water injection–polymer injection–low-salinity water injection, water injection–low-salinity water injection–polymer injection, water injection–low-salinity water–polymer injection, and low-salinity water injection–low-salinity water–polymer injection. Subsequently, low-salinity water–polymer flooding was simulated using the Eclipse 100 simulator to evaluate the effect of polymer injection on oil recovery and oil trapping in the reservoir rock. Finally, simulation results were validated against laboratory data.
The results demonstrated that low-salinity water injection followed by low-salinity water–polymer injection showed the best performance, improving secondary oil recovery by 63.45%, with wettability alteration identified as a key mechanism for enhanced oil recovery. The study also showed that under optimal conditions, despite mechanical degradation of the polymer, recovery of initial oil in place could reach up to 85% through controlled adsorption of polymer on the rock surface. Furthermore, initial polymer injection was found to help reduce the amount of polymer required to achieve residual oil saturation.

Abstract The petrophysical parameters of the Ghar Formation are characterized in this study. A combination of pre-stack seismic data gathers and well-log data is used to estimate water saturation and shale volume in the Ghar reservoir. First, the highest possible correlation between the well logs and the seismic inversion data was established for this purpose. After extracting the optimal wavelet, an accurate relationship between the estimated values and the core data was obtained. Next, using data from another well, the validity of the constructed model was examined. The results showed that the combination of three attributes—instantaneous cosine of phase, , and —can accurately estimate the shale volume of the reservoir, with a correlation coefficient of approximately 70%. Although the two layers in the Ghar section have a shale volume of about 10%, the overall shale volume in the reservoir area is negligible. The logarithm of the ratio of compressional wave velocity to shear wave velocity attribute exhibits the highest correlation, approximately 62%. Finally, validation using previously unutilized well-log data demonstrated an accuracy of about 90% in predicting these properties.

Abstract This work pertains to investigate the values of the stress intensity factor (SIF) in a functionally graded spherical pressure vessel with an embedded surface defect (semi elliptical crack) under thermo-mechanical loading. The three dimensional finite element analysis is performed to evaluate the SIFs through the crack front for a wide range of crack profiles and the various layer thickness. It is assumed that the elastic modulus of sphere varies exponentially in the radial direction of the vessel.

The effect of non-uniform coefficient of thermal expansion (CTE) on the fracture parameters is also studied. The obtained results show that the material gradation of spherical pressure vessel can considerably affect the distribution of the SIFs along the crack front. The gradation of material, the wall thickness of spherical pressure vessel and the profile of crack front can affect the critical point through the crack front which is apt to the crack growth.