Iranian Journal of Oil and Gas Science and Technology

Abstract Column final tests face new challenges, and in addition to casing burst/collapse limitations, buckling occurrence creates serious problems. In case of a slight gap between mud and slurry densities, buckling initiation is inevitable. Casing elongation, bending, and buckling are detailed to define column behavior while testing. Buckling influences on slurry are mentioned and compared to the column without test. A new cement quality indicator is also proposed, tested, and validated via logging of wells drilled in different regions. The results are generalized to cover other situations rather than heavy sections. Further, gas migration regions, depleted reservoirs, and weak zones are all examined. Registrations confirm the appearance of buckling either while pumping slurry or pressure testing. A new modified casing selection method conjointly with an updated numerical technique is proposed to prevent buckling. Moreover, the experimental and simulation findings confirm the reliability of the proposed technique.

Abstract Oil recovery from oil-wet carbonate rock is a significant challenge in the oil industry. The present study investigates the influence of the natural surfactant Hawthorn leaves extract (HLE) on oil recovery from carbonate rock. Two chemical surfactants, sodium dodecyl sulfate (SDS) and dodecyl tri methyl ammonium bromide (DTAB), were used to validate and compare oil recovery with the new natural surfactant HLE. A wettability alteration test using the contact angle method, an interfacial test (IFT) using pendant drop, and core flooding were employed to investigate the behavior of the surfactants on oil recovery. The experimental results show that the critical micellar concentration (CMC) point of different concentrations of HLE, SDS, and DTAB solution occurs at 3.25, 3.00, and 4.06 wt %, respectively. In wettability alteration, the natural surfactant HLE is more effective than other chemical surfactants (SDS and DTAB) at the CMC point. As observed, the contact angle of the carbonate pellet and the HLE at the CMC point is 86°, and this angle for SDS and DTAB is 112° and 92°, respectively. The core flooding results show that the oil recovery factor improves from 37% with water flooding to 47.6% with SDS, 56.2% with DTAB, and 54.7% with HLE. The results prove that this new natural surfactant (HLE) can be used as a novel surfactant for the chemically enhanced oil recovery process in carbonate oil reservoirs. HLE has beneficial effects in oil recovery because of its environment friendly compared to SDS and DTAB.

Abstract In this study, the hydrocarbon potential and depositional environments of the Coniacian Laffan formation were investigated in the Binak oilfield, SW Iran. With an average thickness of 80 m, the Laffan formation consists mainly of gray shales and thin argillaceous limestones in the study area. In order to investigate the hydrocarbon potential, 22 cutting samples from 5 wells of the Binak oilfield were analyzed by Rock-Eval 6 pyrolysis and organic petrographic techniques. The hydrogen index (HI) versus T_max diagrams indicated mixed-type II/III kerogen with a maturity corresponding to the early stages of the oil window (T_max ≈ 435 °C). In addition, plots of S1+ S2 versus TOC were consistent with a weak to excellent hydrocarbon potential for the Laffan formation. On the other hand, organic petrographic techniques indicated that the primary organic constituents of the Laffan formation are inertinite and bituminite with subordinate amounts of amorphous organic matter (AOM). In other words, the contained organic matter was mainly composed of inertinite and lacked significant hydrocarbon potential. An abundance of inertinite and the conspicuous absence of vitrinite macerals in the studied samples suggested that the Laffan formation was deposited under sub-oxic marine conditions. Furthermore, the presence of bituminite in the studied samples greatly influenced the Rock-Eval pyrolysis readings, so geochemical evaluation of the Laffan formation using only Rock-Eval pyrolysis data may lead to erroneous interpretations. Therefore, a combination of Rock-Eval and organic petrographic methods is necessary for reliable geochemical evaluation of the Laffan formation. The results of this study can be useful for a better understanding of the Cretaceous hydrocarbon system in the study area.

Abstract A successful drilling operation requires an effective drilling fluid system. The aim of this work is to provide an effective solution for improving the rheological and filtration properties of water-based drilling fluid by using CuO nanofluid additive. CuO nanoparticles were synthesized by hydrothermal method using autoclave, which can control the temperature as well as pressure. Then CuO nanofluid (eco-friendly ethylene glycol based) were produced to use as a drilling fluid additive. X-ray diffraction, Fourier-transformed infrared, scanning electron microscope were used to characterize nanoparticles. The results confirmed clearly the formation of high purity CuO nanoparticles forming a wire shape structure. The operating parameters were optimized by experimental design method and based on the optimal results, two long time stabilized nanofluids were prepared to improve the rheological properties and the fluid loss of a polymeric water-based drilling fluid. Xanthan, polyanionic cellulose and starch are commonly used in drilling fluids to improve rheological and fluid loss properties. Also, the effect of pH level of nanofluids on the improvement of water-based drilling fluid properties was investigated. The results showed that the nanofluid with pH=8 can be used as the best additive to improve the drilling fluid properties. The improvement of the yield point, apparent viscosity, 10-second and 10-minute gel strengths of the drilling fluid as well as the fluid loss were 45, 33, 200, 100 and 44 %, respectively.

Abstract This research aims to investigate the effect of microwaves on the physical and chemical properties of heavy crude oil in the presence of different minerals. In this regard, the physical and chemical changes of the oil and rock powder (sand and carbonate) mixture are investigated by microwave radiation. Viscosity and temperature changes of two samples are measured. IP143 and elemental analysis (carbon, hydrogen, nitrogen, and sulfur) are used to extract and identify the composition changes of asphaltene. The viscosity and temperature changes show that for both samples at the beginning of microwave radiation, there is a decrease in viscosity due to heavy hydrocarbon particle cracking, such as asphaltene, and converting them into lighter ones. Light compounds evaporate by continuing the radiation and temperature increase; finally, the viscosity increases. The evaporation process in the carbonate powder sample starts earlier than in the sand powder. From elemental analysis, it is concluded that the sulfur and nitrogen in asphaltene decrease almost the same for both samples, and this decrease is more evident for sulfur; thus, the rock powder combined with oil does not have a significant effect on the reduction of these elements. The increase in IFT is also observed due to the evaporation of light oil compounds, and IFT increases further due to the higher temperature of the sample containing carbonate rock powder.

Abstract Permeability is one of the most significant petrophysical parameters of reservoir rock, and its accurate, inexpensive, and rapid estimation is essential. One of the methods for the permeability analysis is the Stoneley flow zone index method. In this study, this method was used to estimate the permeability. For this purpose, after processing the Stoneley waves in the studied well by  Paradigm Geolog software, the permeability index was calculated based on Stoneley wave slowness. Then, by optimizing this index with default values of the flow zone index matching factor (IMF), the flow zone index was calculated, and the permeability value was estimated based on that index. Some parameters required for these calculations, such as porosity, type, and volume of minerals, were determined based on the complete set log analysis and with the help of cross-plots. Finally, these results were compared with the core data to validate the obtained permeability data, and the IMF values were customized for the studied field. The results indicated that the primary lithology of the Asmari formation in the studied well was carbonate rock with a small amount of shale. The customized IMF values for calcite, dolomite, anhydrite, and shale were 11.93, 10.53, 0, and 0, respectively. The correlation coefficient between Stoneley-flow zone index permeability and core permeability was 0.79. Therefore, according to this good correlation, this method can be used to estimate permeability, especially in wells without core data.