Iranian Journal of Oil & Gas Science and Technology
Volume:10 Issue: 2, Spring 2021

Water can contain microorganisms and cause deposition and corrosion in cooling tower systems.Therefore, treatment of thewater of cooling towers is important and essential.Various biocides are used to remove bacteria and disinfect the water of cooling towers,the most commonly used of whichare sodium hypochlorite and chlorine compounds. Two chlorinated water,(hypochlorous acid) and (sodium hypochlorite) were tested in this studyon two pilot and industrial cooling towers.The results of experiments on the pilot tower showed that the performance of hypochlorous acid in disinfection and removal of bacteria and microorganisms has a high capability.The total bacterial count decreased from 10000 (cfu/ml) to less than 800 (cfu/ml) compared to sodium hypochlorite.Experiments and researches were performed on the industrial cooling tower of the Petrochemical Acetic Acid Unit for six months, in which pH, Free Chlorine, TBC and SRB were measured.Very high disinfection power of hypochlorous acid compared to sodium hypochloriteand also low pH of hypochlorous acid compared to sodium hypochlorite led to a significant reduction in the use of chemicals in the cooling tower.The results of Experiments and TBC and SRB tests showed very good performance of using hypochlorous acid

Wellbore stability is of one of challenges in drilling industry. Shale formation is of one of the most problematic rocks during drilling because the rock has very low permeability and very small pores (nanometers). In this study, the viability of the Alumina nanoparticles in Water-Based Mud (WBM) is assessed. The effect of Alumina nanoparticles (alpha and gamma) as mud additives to improve the rheological properties in water- base drilling fluids are experimentally investigated. The Alumina nanoparticles has specific chemical and physical properties such as: high compressive strength, high hardness, high thermal conductivity, these properties improve the rheological properties of water base drilling fluid, reduce filtration loss and meet environmental regulations. The results of experiments indicated that Alumina nanoparticle are improving rheological properties such as: yield point (YP), gel strength (GEL 10s, Gel 10min) of water- base drilling, that can be used to improve the rheological and filtration properties of drilling fluids. The experimental data showed that, Alumina nanoparticle as a Nano additive, possessed excellent properties such as thermal stability, rheology enhancing, fluid loss control and lubrication. Also, it could plug the shale formation effectively and improve the pressure bearing capability of formation significantly. In addition, Alumina nanoparticles reduced 60% API/HPHT fluid loss by 60% in comparison with blank sample. The most striking feature is that shale integrity improved by Nano fluid between 60 and 70 percent in comparison with blank sample. Also, data experimental of CT Scan are shown that the filter cakes formed by each of the Nano-drilling fluid samples with alpha alumina and gamma alumina base are more cohesive and cause an integrated filter cake on the well.

The lithofacies and environments of deposition interpretations of the Calub-Hilala field towards central trough of Ogaden Basin have been carried out. Geophysical well logs from three deep exploration wells; Calub-1, Bodle-1 and Hilala-2 were used. A methodology was piloted in establishing the sedimentary facies, their successions and environments of deposition. Gamma ray, neutron, sonic and resistivity logs were used for lithologic and depositional environment identification respectively. An attempt were also made to identify formation tops and well to well lithostratigraphic correlation basing gamma ray log trends and correlating with cored interval of the wells for Lithological comparisons. Lithofacies interpretation was carried out with Schlumberger’s Petrel 2009TMsoftware. Correlation techniques were conducted to delineate the subsurface trends of these facies with electrafacies to compare facies interpretation results that were implied using the wire line log signatures.Ten (10) formations; Calub, Bokh, Gumburo, Adigrat, Transition, Hamanlei (Lower, Middle and Upper), Urandab, Gebredare, Gorrahei, Mustahil and Five (5) log facies; a cylindrical-shaped log trends representing aeolian, braded fluvial; a funnel-shaped facies representing a crevasse splay; a carbonate shallowing upward sequence and shallow marine sheet sand; bell-shaped facies representing transgressive marine shelf; a symmetrical- shaped facies representing sandy offshore and an irregular shaped facies representing fluvial floodplain were recognized. The environments of deposition delineated for the study area are alluvial and transgressive – regressive marine.

In current work, Perturbed Chain- Statistical Associating Fluid Theory (PC-SAFT) EoS together with the Reaction Equilibrium Thermodynamic Model (RETM) was employed to correlate H2S solubility in three carboxylate ionic liquids including [emim][Ace], [bmim][Ace] and [hmim][Ace]. The RETM proposes a chemical reaction approach between IL (B) and H2S (A) in the liquid phase. Moreover PC-SAFT EoS contributes for VLE calculations. All the H2S and the investigated ILs, as self-associating components, assumed to follow 2B association scheme.Five adjustable variables of PC- SAFT EoS for pure components were calculated using experimental data of liquid density and vapor pressure. Afterwards, the binary systems were investigated applying RETM. Indeed, two nested loops calculate the liquid phase, total pressure and vapor phase concentrations, respectively. For these systems, AAD% equal to 2.29, 3.09 and 7.65 were obtained for all ILs respectively.

One of the important issues in oil industry is related to asphaltene precipitation during different stages, and using nanoparticles is known as a common method for solving this problems. Although nickel oxide and zeolite have been addressed in previous researches for solving asphaltene precipitation problem, Using NiO/Na-ZSm-5 (the main goal of this study) has not been developed for solving relevant asphaltene precipitation problem. The crystalline structure and morphology of the synthesized nanoparticles have been analyzed with the help of XRD, SEM, FTIR and EDX. Results show that the nanoparticles were well synthesized and after synthesis with a diameter of 13.6 nm. The EDX analyses also approved that an amount of asphaltene was adsorbed by the sorbent. Asphaltene adsorption experiments were carried out at various asphaltene concentrations and different temperatures and the effect of different variables of initial asphaltene concentrations, temperature and ratio of heptane to toluene were evaluated on asphaltene adsorption rate. The results indicate that with an increase in the initial asphaltene concentration from 25 to 2000 ppm, the asphaltene adsorption rate in zeolite increases. In concentrations less than 500 ppm, a rise in temperature results in reduced asphaltene adsorption, while at concentrations higher than 500 ppm, with a rise in temperature from 25°C to 55°C, asphaltene adsorption capacity on zeolite increases. Also greater adsorption has been observed for Heptane/Toluene=0.4 with q=25.17 mg/g. For determining the kinetic mechanism of this process, the experimental data were adapted according to Lagrangian pseudo-first and second-order models. The Langmuir and Freundlich adsorption isotherms were evaluated, in which the isotherms resulting from the Langmuir isotherm model were of adequate conformity. This indicates that adsorption at the homogenous level occurred with single-layered coating. In the final step, after evaluating the thermodynamic conditions, the spontaneity of the asphaltene adsorption process was proven.

Although experimental studies confirmed the effectiveness of nanoparticles in enhanced oil recovery applications, no comprehensive investigation has been carried out to reveal the effect of different subsurface factors on this improvement. Proper application of nanoparticles mainly depends on their ability to travel long distances within a reservoir without agglomeration, retention and blocking the pore throats. This study strengthens our understanding about the effect of the main subsurface factors on the nanofluid-assisted enhanced oil recovery. For doing so, a transport approach utilizing kinetic Langmuir model is developed and validated using experimental data. Thereafter, the effect of reservoir rock type and its properties (clay content and grain size), salinity of injected fluid, and reservoir temperature on the transport and retention of nanoparticles in porous media in relation to enhanced oil recovery methods is investigated. Since the amount of nanoparticles in the injected fluid and on the rock surface (as deposited) control the mobility and wettability alteration, the effect of subsurface factors and salinity of injected fluid on this deposition is also analyzed. The results showed that the rock type and its properties significantly affect the transport and retention of nanoparticles in porous media. It was also found that the brine salinity has the greatest impact on the amount of nanoparticles deposited on the rock surface. The surface covered by NPs increased from 10 to 82 % after changing salinity from 3 weight percent NaCl to API brine.

This paper investigates the role of the effective thickness of the Asmari reservoir formation zones on oil production in one of the Iranian carbonate oil fields. Effective thickness is a term that includes the total gross thickness of rocks by lithofacies for a selected wellbore. The lithology of the Asmari Formation in the studied area consists of dolomite, sandstone, lime, dolomitic-lime, sandstone-shale, and shale limestone dolomites. Based on the existing well-logs, the average shale volume, the effective arithmetic means of porosity in the gross intervals, and average water saturation or hydrocarbon-bearing increments of the studied field is calculated from well-logs. The depth interval of 2214 to 2296, in wellbore #A shows 9.6% average shale volume, 27.2% average water saturation, and 20.9% average porosity. The depth interval of 2213 to 2280, in wellbore #B, shows 6% average shale volume, 21.25% average water saturation, and 28.5% average porosity. Based on our petrophysical assessments we divide the Asmari reservoir in the studied field into eight zones. Zone 1 is made of carbonate (calcareous and dolomitic), zones 2 to 5 are mainly sandstone, zones 7 and 8 are calcareous and shale and zone 6 is a mixture of all the above-mentioned rocks. Among these eight zones, there are two main hydrocarbon productive zones. The numerical calculation of in situ oil volume showed that zone two contains 65% of oil volume in this reservoir. This zone with more than 80% of sand has the highest net hydrocarbon column.