Petroleum Engineering
Yaser Ahmadi
Abstract
Recently nanoparticles are used for improving the volume of oil and gas production and Enhanced Oil Recovery (EOR) purposes. Based on our recent researches, using nanoparticles such as Silica and Calcium oxide has a good potential for changing mechanisms in the porous media such as interfacial tension ...
Read More
Recently nanoparticles are used for improving the volume of oil and gas production and Enhanced Oil Recovery (EOR) purposes. Based on our recent researches, using nanoparticles such as Silica and Calcium oxide has a good potential for changing mechanisms in the porous media such as interfacial tension and wettability. For finding the application of nanoparticles in the porous media, low permeability carbonate plugs were selected, and two main steps were used , including 1) Using CaO and SiO2 nanoparticles for wettability alteration, interfacial tension reduction, and improving fluid flow through porous media 2) Surveying the application of nanoparticles on the water alternative gas (NCs assisted WAG) test. The Zeta potential amounts are stable at condition of -56.4±2 mV and -44.0±3 mV for Calcium oxide and Silica nanoparticles, respectively at optimum nanoparticles concentration of 15 ppm. Calcium oxide and Silica nanoparticles have effectively altered the wettability from oil-wet to water-wet by surveying the intersection of two-phase relative permeability. Moreover, CaO nanoparticles had better performance in low permeability carbonate porous media than SiO2 nanoparticles with regards to wettability alteration to water wet. Based on the results and better version of CaO, it was selected for performing NCs assisted WAG tests at WAG ratios of 1:1, 40 ℃, and 15 ppm.The recovery factor was increased from 42.9 % to 73 % in the presence of CaO during performing NCs assisted WAG tests, and residual oil saturation was decreased from 40.9 % to 19.4 %.
Petroleum Engineering
Abdeslem Leksir
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 ...
Read More
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.
Petroleum Engineering
Bardiya Yazdani; Amir Hossein Saeedi Dehaghani
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. ...
Read More
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.
Petroleum Engineering
Meisam Hemmati; Yaser Ahmadi
Abstract
The Rock-Eval pyrolysis is a thermal method that is widely used by the petroleum geologist for evaluation of source rock characteristics and obtain geochemistry parameters. However, there are misconceptions and misuses in exceptional cases that could lead to erroneous conclusions after using the Rock-Eval ...
Read More
The Rock-Eval pyrolysis is a thermal method that is widely used by the petroleum geologist for evaluation of source rock characteristics and obtain geochemistry parameters. However, there are misconceptions and misuses in exceptional cases that could lead to erroneous conclusions after using the Rock-Eval pyrolysis data to evaluate the properties of organic matter. However, a cross-plot of S2 (petroleum potential) versus TOC (total organic carbon) is the usable tool to solve issues and applied for checking the accuracy of the geochemistry parameters. The graph provides the correction criteria for the S2, HI (hydrogen index), and kerogen type. As well as, the graph measures the adsorption of hydrocarbon by the mineral matrix. In addition, this article demonstrates a manner based on the data plot of S2 versus TOC to detect bitumen or hydrocarbon contaminations. Based on our knowledge about the Garau Formation as a possible source rock in petroleum geology of Iran, a geochemistry study by Rock-Eval VI pyrolysis and Leco Carbon Analyzer has been conducted on many rock samples collected from different outcrops in the Lurestan province, Aligudarz region, from South-West of Iran, High Zagros. Plotting the data on a cross plot of S2 versus TOC, drawing the regression line, and finding the regression equation are the best method for determining the real values of S2 and HI parameters and bitumen/hydrocarbon contamination. Contamination creates a y-intercept in the graph of S2 versus TOC which makes geochemistry data unreliable in two study location. As, led to the S2 and HI data unrealistically increased, while the Tmax values went down and reduced the thermal maturity of the organic matters from its real status. For skipping the effect of contamination and obtaining the real geochemistry parameters, the y-intercept of the graphs removed and the corresponding values subtracted from the HI and S2. The cause of contamination in the Garau Formation is the adhesion of heavy bitumen to organic facies due to the covalent bonds between carbon and hydrogen ions.
Petroleum Engineering
Amin poorzangheneh; Bijan ghanavati; Borzu Asgari pirbalouti
Abstract
Oil well cementing is a multi-purpose operation, in which cement slurries are prepared by mixing water, cement and various additives and is pumped into the well in order to isolate productive zones, protect the casing pipe, perform remedial operations, controlling drilling fluid lost or abandon the well. ...
Read More
Oil well cementing is a multi-purpose operation, in which cement slurries are prepared by mixing water, cement and various additives and is pumped into the well in order to isolate productive zones, protect the casing pipe, perform remedial operations, controlling drilling fluid lost or abandon the well. Various additives are used to improve the mechanical properties of the slurry. Weight-enhancing additives are materials with specific gravity higher than cement, which increase the weight of the slurry. Improving the mechanical properties of these type of cement slurries has always been an important issue in the discussion of oil wells cementing. In this study, the effects of nano zeolite on heavy-weight oil well cement slurry were investigated in laboratory to improve the rheological and mechanical properties of the cement. In the designed experiments, nano-zeolite was added to the slurry with the amount of 1, 2 and 3% BWOC. The results showed that nano zeolite acts as an additive to reduce the thickening time, increase the plastic viscosity and reduces the yield point of the slurry. The experiments also showed that in general, the addition of nano-zeolite to the cement slurry from 1 to 3% BWOC led to an increase in the free fluid of the cement slurry, but did not show any effect on the control of the fluid loss. Finally, by adding 2% BWOC of nano zeolite, the compressive strength of the cement stone increased and the initial setting time of cement slurry decreased.
Petroleum Engineering
JOSHUA LELESI KONNE; Ogochukwu Vivian Udeh; Grace Agbizu Cookey; GODWIN CHUKWUMA JACOB NMEGBU
Abstract
Increasing demand of hydrocarbons has prompted new strategies of recovery by application of nanoparticle-surfactant flooding in Chemical Enhanced Oil Recovery (CEOR). Some mechanisms involved in improving oil mobility are alteration of rock wettability and reduction in interfacial tension between the ...
Read More
Increasing demand of hydrocarbons has prompted new strategies of recovery by application of nanoparticle-surfactant flooding in Chemical Enhanced Oil Recovery (CEOR). Some mechanisms involved in improving oil mobility are alteration of rock wettability and reduction in interfacial tension between the oil and water. In this work, silica (SiO2) nanoparticles (NPs) were synthesized, characterized and their effect on wettability alteration and interfacial tension (IFT) between the oil and SiO2 NPs dispersed in Sodium dodecyl sulphate (SDS) solutions was determined. Experiments on displacement of oil by flooding with brine and NPs dispersed in SDS solution were investigated in a micro glass model. X-ray Diffraction (XRD) pattern and Scanning Electron Microscopy (SEM) confirmed the mineral structure and platy polycrystallite morphologies that gave an estimated particle size of 88 nm using Scherrer’s formula. Fourier Transform Infrared Spectroscopy (FTIR) showed characteristic symmetric and asymmetric stretching vibrations. The wettability alteration and IFT measured showed changes in wettability from water-wet towards a more water-wet condition and a decrease in IFT respectively as the SDS concentration increased. The optimum oil recovery of 67.45% was obtained at 2.08 mM SDS when SDS concentrations were varied (2.08, 6.25, 8.33, 10.42 and 14.58 mM) at constant SiO2 NPs (0.1% wt.). Having obtained the optimum oil volume from OOIP at 2.08 mM SDS, SiO2 NPs concentration was varied (0.05, 0.1, 0.15, 0.2 and 0.25% wt.) at constant SDS concentration (2.08 mM). This optimized approach gave an excellent total oil recovery of 78.36% at 0.2% wt. SiO2NPs. It is therefore recommended that 0.2% wt. SiO2NPs with 2.08 mM SDS be applied in oil recovery.
Petroleum Engineering
Meisam Hemmati; Yaser Ahmadi
Abstract
Knowing the characteristics of suitable environments for precipitation of oil prone source rocks facilitates oil explorations and leads to development of oil fields. The current study investigates the organic matter properties and sedimentary environment conditions of the Garau Formation in various outcrop ...
Read More
Knowing the characteristics of suitable environments for precipitation of oil prone source rocks facilitates oil explorations and leads to development of oil fields. The current study investigates the organic matter properties and sedimentary environment conditions of the Garau Formation in various outcrop sections in Lurestan province from south-west of Iran (High Zagros) with using elemental analysis, visual kerogen analysis and Rock-Eval pyrolysis data. The geochemistry parameters indicate that the Garau Formation is an excellent oil prone source rock and composed of kerogen type I and II. The oxygen index (OI) is very low which reveals that organic matter deposited in an anoxic sedimentary environment and suitable for the preservation of organic matter and hydrocarbon generation. The visual analysis of isolated kerogens from source rock samples indicates the abundance of dark amorphous organic matter (AOM) with small amounts of phytoclasts and pyrite with no palynomorphs. Sedimentation seems to have occurred in deep and reduced parts of a carbonate basin during a rapid transgression. In addition, due to the effect of thermal maturation, the color of amorphous organic matter has darkened. The elemental analysis and Van-Krevelen diagram was shown that the type of organic matter and reveals the thermal maturity of the oil window. Moreover, amount of pyritic sulfur (Sp) and organic sulfur (So) contents have been calculated, and it was reveals that the high content of organic sulfur is a key element in the structure of organic matter.
Petroleum Engineering
AliPanah Rostamzadeh; Seyed Aboutaleb Mousavi Parsa; Faramarzi Mehdi
Abstract
One of the most important ways to enhance oil recovery in oil reservoirs is chemical flooding. The study of performance and efficiency of these processes in increasing the range of oil recovery from reservoirs depends on several factors, including the rock and fluid properties of the reservoir, and therefore ...
Read More
One of the most important ways to enhance oil recovery in oil reservoirs is chemical flooding. The study of performance and efficiency of these processes in increasing the range of oil recovery from reservoirs depends on several factors, including the rock and fluid properties of the reservoir, and therefore one of the most important steps in evaluating the performance of these methods for a reservoir is the laboratory study and calculating the chemical agent potential to recover oil. For this purpose, a laboratory study and integrated simulation in order to identify the effective mechanisms in the injection of smart water polymer in order to identify the necessary and dominant conditions of this method was performed to improve the recovery of Iranian carbonate reservoirs. Initially, four injection scenarios, water injection-polymer injection-smart water injection, water injection-smart water injection-polymer injection, water injection-smart water polymer injection and smart water injection- smart water polymer injection were tested in a laboratory and then simulation of smart water polymer flooding using Eclipse simulator 100 and the effect of polymer injection on oil recovery and oil trapping in the reservoir rock was performed and finally the results of the simulator and the results of laboratory data were validated. The results showed that smart water injection- smart water polymer injection have better performance in improving secondary oil recovery by 63.45% and wettability changing is one of the main mechanisms to improve oil recovery. The results also showed that in optimal conditions, despite the mechanical degradation of the polymer, initial oil in place recovery is achieved up to 85% by controlled adsorption of polymer on the rock surface.
Petroleum Engineering
Mehdi Amiri; Jafar Qajar; Azim Kalantariasl
Abstract
Sarvestan and Saadatabad oilfields produce more than 140 bbl/day of wastewater due to oil processing. Due to environmental issues, the produced water is injected into a disposal well through a pipeline with a diameter of 8 inch and a length of 5 km. Formation of inorganic scale may accelerate the need ...
Read More
Sarvestan and Saadatabad oilfields produce more than 140 bbl/day of wastewater due to oil processing. Due to environmental issues, the produced water is injected into a disposal well through a pipeline with a diameter of 8 inch and a length of 5 km. Formation of inorganic scale may accelerate the need for frequent reservoir acid stimulation, restrict flow path, and generally add unpredicted costs for water injection operations. This study predicts scaling tendency and examines scale precipitation at different pressures, temperature, and mixing ratios of injection wastewater with formation water in Sarvestan and Saadatabad oilfields. The experimentally measured chemical analysis of the injection water and formation water was used to estimate the amount, type, and composition of scale due to mixing and changes in thermodynamic conditions. Scaling tendency values for eight types of scale, namely CaCO3 (calcite), CaSO4 (anhydrite), CaSO4.2H2O (gypsum), FeCO3 (siderite), Fe(OH)2 (amorphous), NaCl (halite), Mg(OH)2 (pyrochroite), and KCl (sylvite), were investigated by commercial software packages OLI ScaleChem and StimCADE. The results show that the significant scales are CaCO3 and FeCO3 formed in Sarvestan and Saadatabad oilfields. The formation of these scales can lead to severe problems, such as disrupting equipment and decreasing production; thus, it is necessary to predict all types of scales before forming. It allows design and planning for chemical inhibitor treatment and prediction of injectivity problems and acid stimulation.
Petroleum Engineering
Borzu Asgari pirbalouti
Abstract
This study investigated the application of iron oxide nanoparticles in the presence of an external magnetic field to control the rheology of drilling fluids. Drilling fluid rheology is one of the most critical factors in determining the optimal fluid. Drilling fluid must have good rheological properties ...
Read More
This study investigated the application of iron oxide nanoparticles in the presence of an external magnetic field to control the rheology of drilling fluids. Drilling fluid rheology is one of the most critical factors in determining the optimal fluid. Drilling fluid must have good rheological properties to carry the drilled cuttings. On the other hand, polymers in the water-based drilling fluid control fluid loss. In low-density oil-based fluids, where the water content is low, rheological control is generally difficult since there is a limitation in selecting additives. In this study, the ferromagnetic fluid has been generated by adding nanoparticles of Fe3O4 to silicon oil. By adding ferromagnetic fluid to the oil-based mud under the influence of the external magnetic field, we examined the rheological behavior of the oil-based drilling mud. The external magnetic field can be applied in actual conditions in the middle of a magnetic drilling string. The results showed that the magnetic nanoparticles improved the drilling mud rheological properties. Moreover, the viscosity of the oil-based fluid without nanoparticles was measured 2 cP and increased to 33 cP by adding 4 wt % of iron oxide nanoparticles under an external magnetic field of 0.321 T. The magnetic field was also used for water-based mud (WBM), and the results showed that in water-based fluids containing polyanionic cellulose (PAC) polymer, the magnetic field did not have much effect on the rheological properties of the drilling mud compared to oil-based mud (OBM). Since water is the main component of the water-based fluid, increasing the magnetic field reduces the viscosity of the water-based fluid. The magnetic field increased fluid’s rheology by adding iron oxide nanoparticles to the polymer-based fluid. The viscosity of the water-based fluid containing nanoparticles increased to 850 cP under the magnetic field.
Petroleum Engineering
Siavash Ashoori; Ehsan Safavi; Jamshid Moghaddasi; Parvin Kolahkaj
Abstract
Formation damage is reported during the secondary and tertiary stages of reservoir lifespan. One of the unpleasant sequences of formation damage caused by fine particles is permeability reduction due to pore plugging and bridging. The fine particles might exist initially in a porous medium or be introduced ...
Read More
Formation damage is reported during the secondary and tertiary stages of reservoir lifespan. One of the unpleasant sequences of formation damage caused by fine particles is permeability reduction due to pore plugging and bridging. The fine particles might exist initially in a porous medium or be introduced by external sources. In addition, there is a variety of particle types and sizes. The current research focuses on the effects of non-swelling clay minerals motions, such as the laminar ones found in Iranian sandstone reservoirs, on permeability. For this purpose, sand packs in various glass bead sizes and containing aluminum oxide as fine particles were designed to scrutinize the motion of fine particles under various pressure differences, flow rates, and concentrations. It was concluded that for each of the three sand packs regarded as the porous media in this study and composed of fine glass beads with different sizes, there is a critical flow rate as a function of glass bead size. For the flow rates lower than the critical flow rate, bridges form stably and lead to the most severe formation damage. After reaching the critical flow rate, the bridges weaken and break, and relative permeability will be independent of the flow rate. It was deduced that permeability reduction and formation damage are directly proportional to particle concentration and inversely proportional to glass bead size.
Petroleum Engineering
Nima Hamidian Shoormasti; Seyyedalireza Tabatabaei-Nezhad
Abstract
Shale formations are essential for different disciplines, including wellbore stability studies in petroleum engineering. In shale stability studies, the prediction of transport parameters of water and ions is a significant issue (Farrokhrouz and Asef, 2013). A unique and novel method to address this ...
Read More
Shale formations are essential for different disciplines, including wellbore stability studies in petroleum engineering. In shale stability studies, the prediction of transport parameters of water and ions is a significant issue (Farrokhrouz and Asef, 2013). A unique and novel method to address this subject is the Revil model (Revil et al., 2011), which, unlike previous models, considers physiochemical mechanisms in the pore space and needs a few easily measurable shale properties (Revil et al., 2004). In this paper, for the first time to our knowledge, the Revil model has been extended for salts of multivalent ions. The extended model for water and ion transport through shale has been evaluated against a range of experimental data sets in the literature. The extended Revil model only needs a few shale properties such as cation exchange capacity (CEC), porosity, and grain density, which can be readily measured in the laboratory. Further, in the present work, three parameters ( ) have been considered calibration parameters. In addition to extending the Revil model for multivalent salts, we derived a simplified equation to estimate ion selectivity (IS) and a proof for the conjecture that IS correlates with membrane efficiency (ME). Focusing on the data set of Albazali (2005), a complete matching could be obtained by adjusting calibration parameters for each test data. In the case of adjusting all experiments with only three standard calibration parameters, the prediction was not satisfactory. However, the “intact-anion method” results were more accurate than the “Donnan method”. When multiple sets of ME data in a broader concentration range, including low concentrations, were plotted along with high-concentration data, correlativity was significant (R2 > 0.9). Further, a sensitivity analysis of the model parameters was performed. Our findings pave the way for the appropriate mechanistic approach to investigating and handling practical engineering challenges associated with shale.
Petroleum Engineering
Yaser Ahmadi
Abstract
Using nanoparticles for adsorbing asphaltene is an efficient method for upgrading actual oil samples compared to other expensive mechanical treatments or even solvents, such as n-pentane and n-heptane, and surfactants. This study uses nickel–zeolite oxide nanoparticles for asphaltene adsorption ...
Read More
Using nanoparticles for adsorbing asphaltene is an efficient method for upgrading actual oil samples compared to other expensive mechanical treatments or even solvents, such as n-pentane and n-heptane, and surfactants. This study uses nickel–zeolite oxide nanoparticles for asphaltene adsorption and solving asphaltene precipitation problems. Although nickel–zeolite oxide nanoparticles have been used in previous studies as an asphaltene adsorbent, observing the relationship between asphaltene adsorption on their surface and asphaltene precipitation in the presence of nanoparticles during the actual process is not covered. For addressing this relation, we performed a series of experiments included Fourier-transform infrared spectroscopy (FTIR), CO2–oil interfacial tension tests, Langmuir and Freundlich isotherm models, and natural depletion tests in the presence of nickel–zeolite oxide nanoparticles. The Langmuir model better fitted the adsorption data than the Freundlich model, which shows that the adsorption occurs on a homogeneous surface with monolayer coverage. Based on the CO2–oil interfacial tension results, there are two different slope forms in interfacial tension readings as pressure increases from 150 to 1650 psi. Due to asphaltene aggregation, the second slope (900–1650 psi) is slower than the first one (150–900 psi). Three pressures of 1350, 1500, and 1650 psi and nickel–zeolite oxide nanoparticles at a concentration of 30 ppm were selected for the natural depletion tests, and the basis of selection was high-efficiency adsorption at these points. As pressure decreased from 1650 to 1350 psi, asphaltene precipitation changed from 8.25 to 10.52 wt % in the base case, and it varied from 5.17 to 7.54 wt % in the presence of nickel–zeolite oxide at a concentration of 30 ppm. Accordingly, nickel–zeolite oxide nanoparticles adsorbed asphaltene on their surface correctly, and the amount of asphaltene precipitation decreased in the presence of nickel–zeolite oxide nanoparticles.
Petroleum Engineering
Mohsen Mansouri; Mehdi Parhiz; Behrouz Bayati; Yaser Ahmadi
Abstract
One of the critical issues in the oil industry is related to asphaltene precipitation during different stages, and using nanoparticles is known as a standard method for solving this problem. Although nickel oxide and zeolite have been addressed in previous research to solve the asphaltene precipitation ...
Read More
One of the critical issues in the oil industry is related to asphaltene precipitation during different stages, and using nanoparticles is known as a standard method for solving this problem. Although nickel oxide and zeolite have been addressed in previous research to solve the asphaltene precipitation problem, using NiO/Na-ZSm-5 (the primary goal of this study) has not been developed to solve relevant asphaltene precipitation problems. The crystalline structure and morphology of the synthesized nanoparticles were analyzed with the help of X-ray diffraction spectrometry (XRD), scanning electron microscopy (SEM), Fourier transform infrared spectroscopy (FTIR), and energy-dispersive X-ray spectroscopy (EDXS). The results show that the nanoparticles were well synthesized and preserved their crystalline structure with a diameter of 13.6 nm after synthesis. The EDXS analyses also proved that the sorbent adsorbed an amount of asphaltene. In the next step, asphaltene adsorption experiments were carried out at various concentrations of asphaltene and temperatures, and the effect of different variables, including the initial concentration of asphaltene, temperature, and the ratio of heptane to toluene, on the asphaltene adsorption rate was evaluated. The results indicate that with an increase in the initial asphaltene concentration from 25 to 2000 ppm, the asphaltene adsorption rate in zeolite increases. At concentrations less than 500 ppm, a rise in the temperature reduces the asphaltene adsorption, while at concentrations higher than 500 ppm, raising the temperature from 25 to 55 °C increases asphaltene adsorption capacity on zeolite. Further, more significant adsorption is observed at a heptane-to-toluene ratio of 0.4 with q = 25.17 mg/g. Evaluating the effects of kinetic adsorption molecules of asphaltene on these nanoparticles shows that the adsorption process reaches equilibrium in less than 2 h. The experimental data were adapted according to Lagrangian pseudo-first-order and pseudo-second-order models to determine the kinetic mechanism of this process. The Langmuir and Freundlich adsorption isotherms were evaluated, and the isotherms resulting from the Langmuir isotherm model were of good conformity, indicating that adsorption at the homogenous level occurred with a single-layered coating. In the final step, after evaluating the thermodynamic conditions, the spontaneity of the asphaltene adsorption process was proved.
Petroleum Engineering
Mehdi Rezaei Abiz; Saeid Norouzi Apourvari; Saeed Jafari; Mahin Schaffie
Abstract
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 ...
Read More
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 of the effect of the main subsurface factors on the nanofluid-assisted enhanced oil recovery. To this end, a transport approach utilizing the kinetic Langmuir model is developed and validated using experimental data. After that, the effects of reservoir rock type and its properties (clay content and grain size), the salinity of injected fluid, and the reservoir temperature on the transport and retention of nanoparticles in porous media concerning enhanced oil recovery methods are investigated. Since the concentration 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. Brine salinity also has the most significant impact on the amount of nanoparticles deposited on the rock surface. The surface covered by nanoparticles increased from 10% to 82% after changing salinity from 3 wt % NaCl to the API brine.
Petroleum Engineering
James Sunday Abe; Kenneth Okosun
Abstract
Modelling involves the use of statistical techniques or analogy data to infill the inter-well volume producing images of the subsurface. Integration of available data sets from “KO” field were used to identify hydrocarbon prospects and by means of interpolation, populate the facies and petrophysical ...
Read More
Modelling involves the use of statistical techniques or analogy data to infill the inter-well volume producing images of the subsurface. Integration of available data sets from “KO” field were used to identify hydrocarbon prospects and by means of interpolation, populate the facies and petrophysical distribution across the field to define the reservoir properties for regions with missing logging data[KO1] . 3D seismic data, check-shot data, and a series of well logs of four wells were analyzed, and the analysis of the well logs was performed using the well data. The synthetic seismogram produced from the well ties [M.N.2] [KO3] was used to map horizon slices across the reservoir regions. Four horizons and fifteen faults, including one growth fault, four major faults, and other minor faults, all in the time domain were mapped. Attribute analyses were carried out, and a 3D static model comprised of the data from the isochore maps, faults, horizons, seismic attributes, and the various logs generated was built. A stochastic method was also employed in populating the facies and petrophysical models. Two hydrocarbon-bearing sands (reservoirs S1 and S2) with depth values ranging from –1729 to 1929 m were mapped. The petrophysical analysis gave porosity values ranging from 0.18 to 0.24 across the reservoirs, and the permeability values ranged from 2790 to 5651 mD. The water saturation (Sw) of the reservoirs had an average value of 50% in reservoir S1 and 47% in reservoir S2. The depth structure maps generated showed an anticlinal structure in the center of the surfaces, and the mapped faults with the four wells were located in the anticlinal structure. The reserve estimate for the stock tank oil initially in place (STOIIP) of the reservoirs was about 70 mmbbl, and the gas initially in place (GIIP) of the reservoirs ranged from 26714 to 63294 mmcf. The result of the petrophysical analysis revealed the presence of hydrocarbon at favorable quantities in the wells, while the model showed the distribution of these petrophysical parameters across the reservoirs. Modelling involves the use of statistical techniques or analogy data to infill the inter-well volume producing images of the subsurface. Integration of available data sets from “KO” field were used to identify hydrocarbon prospects and by means of interpolation, populate the facies and petrophysical distribution across the field to define the reservoir properties for regions with missing logging data[KO1] . 3D seismic data, check-shot data, and a series of well logs of four wells were analyzed, and the analysis of the well logs was performed using the well data. The synthetic seismogram produced from the well ties [M.N.2] [KO3] was used to map horizon slices across the reservoir regions. Four horizons and fifteen faults, including one growth fault, four major faults, and other minor faults, all in the time domain were mapped. Attribute analyses were carried out, and a 3D static model comprised of the data from the isochore maps, faults, horizons, seismic attributes, and the various logs generated was built. A stochastic method was also employed in populating the facies and petrophysical models. Two hydrocarbon-bearing sands (reservoirs S1 and S2) with depth values ranging from –1729 to 1929 m were mapped. The petrophysical analysis gave porosity values ranging from 0.18 to 0.24 across the reservoirs, and the permeability values ranged from 2790 to 5651 mD. The water saturation (Sw) of the reservoirs had an average value of 50% in reservoir S1 and 47% in reservoir S2. The depth structure maps generated showed an anticlinal structure in the center of the surfaces, and the mapped faults with the four wells were located in the anticlinal structure. The reserve estimate for the stock tank oil initially in place (STOIIP) of the reservoirs was about 70 mmbbl, and the gas initially in place (GIIP) of the reservoirs ranged from 26714 to 63294 mmcf. The result of the petrophysical analysis revealed the presence of hydrocarbon at favorable quantities in the wells, while the model showed the distribution of these petrophysical parameters across the reservoirs. [KO1]Sentence has been rephrased. [M.N.2]This verb does not make sense in this context and has made the sentence unclear. [KO3]Sentence has been rephrased
Petroleum Engineering
Arian Ahmadi; Mohammad Abdideh
Abstract
< p>The determination of rock types for petrophysical studies has a wide range of applications. It is widely used in drilling, production, and especially in the study and characterization of reservoirs. Zoning of flow units and permeability estimation is one of the challenging tasks of reservoir ...
Read More
< p>The determination of rock types for petrophysical studies has a wide range of applications. It is widely used in drilling, production, and especially in the study and characterization of reservoirs. Zoning of flow units and permeability estimation is one of the challenging tasks of reservoir studies, which uses the integration of data from well logs and analysis of the core. In this study, a Bayesian theory-based statistical modeling method is proposed to identify hydraulic flow units in coreless wells using the concept of hydraulic flow unit and then permeability estimation. In the flow zone indicator (FZI) method, the formation is divided into five hydraulic flow units. In the Winland R35 ethod, however, it is divided into four hydraulic flow units. The Bayesian statistical model divides the existing complex carbonate reservoir rock data into three hydraulic flow units with the most probability of similarity. The second and third hydraulic flow units have closer properties compared to the first hydraulic unit. The Bayesian method-based permeability estimation modeling has acceptable precision, and validation of its results with core data indicates a precision factor of 0.96. The findings of this study can help in better understanding of the concept of flow units and more effective estimation of the permeability of the rocks of the heterogeneous carbonate reservoir.
Petroleum Engineering
Seyed Mohammadreza Mousavi; Saeed Jafari; Mahin Schaffie; Saeid Norouzi Apourvari
Abstract
Ultrasonic irradiation is a new, economic, and environmentally friendly technique for treating asphaltene aggregation in petroleum industry. In this study, the effect of ultrasonic radiation on asphaltene formation is investigated using conventional optical microscopy, viscosity measurement, and Fourier-transform ...
Read More
Ultrasonic irradiation is a new, economic, and environmentally friendly technique for treating asphaltene aggregation in petroleum industry. In this study, the effect of ultrasonic radiation on asphaltene formation is investigated using conventional optical microscopy, viscosity measurement, and Fourier-transform infrared spectroscopy (FTIR). To this end, five crude oil samples, collected from different reservoirs, are used, and the effect of ultrasonic radiation on the structure of the crude oils is investigated at various exposure times. The results show that, at an optimum radiation time, the ultrasonic waves can break the asphaltene clusters and shift the size distribution of the asphaltene aggregate to a smaller size. In addition, the FTIR analysis reveals structural changes in the composition of the crude oil after the ultrasonic irradiation. By increasing the ultrasound exposure time, the viscosity of the asphaltenic oil first decreases to a minimum before rising again. Moreover, the measurement of asphaltene and resin content of the crude oils indicates that at exposure times longer than the one leading to the minimum viscosity, resin molecules are broken upon exposure to ultrasound. This can be the main reason for the existence of an optimum time in the application of ultrasonic radiation, after which the percentage of asphaltene particles and the viscosity of the crude oils increase.
Petroleum Engineering
Mehdi Bahari Moghaddam; Mostafa Fathalizade
Abstract
Enhanced oil recovery (EOR) is a vital part of the process of oil production from sandstone and carbonate reservoirs. Maintaining and increasing oil production from many fields require proper selection, design, and implementation of EOR methods. The selection of EOR methods for specific reservoir conditions ...
Read More
Enhanced oil recovery (EOR) is a vital part of the process of oil production from sandstone and carbonate reservoirs. Maintaining and increasing oil production from many fields require proper selection, design, and implementation of EOR methods. The selection of EOR methods for specific reservoir conditions is one of the most difficult tasks for oil and gas companies. Screening of different EOR techniques considering previous experiences from the methods applied in other fields is a first step in the recommendation of any costly EOR operations. In this paper, EORgui software was utilized to screen eight enhanced oil recovery methods in one of Iran’s offshore sandstone oil fields. The reservoir is composed of two sections with different fluid properties, namely API, viscosity, and oil composition, but relatively homogeneous rock properties and high permeability (1500 mD). The results show that polymer flooding is technically the most suitable enhanced oil recovery method in the upper zone of the reservoir with a high percentage matching score of 90%, and immiscible gas injection with a matching score of 83% is ranked second. For the lower part of the reservoir containing a fluid with much higher viscosity, immiscible gas injection (83% matching) can be recommended. Furthermore, polymer flooding predictive module (PFPM) was utilized to investigate the impact of polymer concentration on oil recovery performance of the upper part with an ultimate recovery of about 40% at the optimum concentration.
Petroleum Engineering
Mostafa Jafari; Mohammad shahab Deljoo; Ali Vatani
Abstract
Today, one of the challenging issues all over the world is the appropriate use of flare gases in oil, gas, and petrochemical industries. Burning flare gases having high heating value results in economic losses and the pollution of the environment. There are several methods to use flare gases; the heat ...
Read More
Today, one of the challenging issues all over the world is the appropriate use of flare gases in oil, gas, and petrochemical industries. Burning flare gases having high heating value results in economic losses and the pollution of the environment. There are several methods to use flare gases; the heat and power generation, the production of valuable fuels, or the separation of more precious components are examples of these methods. In this study, a polygeneration system is designed and simulated for the coproduction of power, steam, methanol, H2, and CO2 from the flare gases in South Pars and Assaluyeh gas fields. The polygeneration system has advantages such as reducing greenhouse gases and the coproduction and sales of energy-related products. The polygeneration system for converting flare gases to energy and various products includes an acid gas removal unit, a synthesis gas production unit, a methanol synthesis unit, a hydrogen purification unit, a combined heat and power generation unit, and a CO2 capture unit. The purpose of this study is to conduct an economic evaluation of the polygeneration system and obtain the total capital cost, the operating profit, and the payback period of this process. The simulation results show that using 9690 kg/h of flare gases produces 8133 kg/h methanol, 653.7 kg/h hydrogen, 46950 kg/h nitrogen, 9103 kg/h CO2, 109850 kg/h medium-pressure steam, and 3.7 MW power. The economic evaluation results show that in the polygeneration system, the total raw material cost and the total utilities consumption cost are $193.8 and $1859.5 per hour respectively, and the total product sales and the total utility sales are $12941.8 and $2243.5 per hour respectively; also, the operating profit is $13132 per hour. Also, the equipment cost, the installation cost, the total capital cost, and the total operating cost are $29.7 million per year, $39.2 million per year, $71 million per year, and $27.9 million per year respectively; finally, the payback period is 1.5 years.
Petroleum Engineering
Mojtaba Ghaedi; Sadegh Ahmadpour
Abstract
The imbibition process is known as one of the main production mechanisms in fractured reservoirs where oil/gas-filled matrix blocks are surrounded by water-filled fractures. Different forces such as gravity and capillary play a role in production from a fractured reservoir during imbibition and complicate ...
Read More
The imbibition process is known as one of the main production mechanisms in fractured reservoirs where oil/gas-filled matrix blocks are surrounded by water-filled fractures. Different forces such as gravity and capillary play a role in production from a fractured reservoir during imbibition and complicate the imbibition process. In previous works, single-parameter models such as the Aronofsky model and Lambert W function were presented to model imbibition recovery from matrix blocks. The Aronofsky model underestimates early time recovery and overestimates late time recovery, and Lambert W function is suitable for water wet cases. In this work, a data bank of different experimental and numerical imbibition recovery curves at various rock and fluid properties were collected. Then, a rigorous analysis was performed on the models utilized to describe oil/gas recovery during the imbibition process. In addition to investigating the single-parameter models, two-parameter models used for dose-response modeling, including Weibull, beta-Poisson, and Logit models were examined. The results of this work demonstrate that using two-parameter models can improve the prediction of imbibition behavior. Moreover, among the two-parameter models, the Weibull has the capability to describe the imbibition process better. The Aronofsky model underestimates early time recovery and overestimates late time recovery, and Lambert W function is suitable for water wet cases. In this work, a data bank of different experimental and numerical imbibition recovery curves at various rock and fluid properties were collected. Then, a rigorous analysis was performed on the models utilized to describe oil/gas recovery during the imbibition process. In addition to investigating the single-parameter models, two-parameter models used for dose-response modeling, including Weibull, beta-Poisson, and Logit models were examined. The results of this work demonstrate that using two-parameter models can improve the prediction of imbibition behavior. Moreover, among the two-parameter models, the Weibull has the capability to describe the imbibition process better.
Petroleum Engineering
Fahimeh Mirzaei; Ahad Ghaemi
Abstract
In this research, the rate of CO2 absorption into methyl diethanolamine–piperazine (MDEA–PZ) solution was investigated. To model the mass transfer flux in the reactive absorption processes, the dimensionless parameters of the process were obtained using the Buckingham Pi theorem and considering ...
Read More
In this research, the rate of CO2 absorption into methyl diethanolamine–piperazine (MDEA–PZ) solution was investigated. To model the mass transfer flux in the reactive absorption processes, the dimensionless parameters of the process were obtained using the Buckingham Pi theorem and considering the effective parameters in mass transfer. The CO2 mass transfer flux in the reactive absorption process depends on the mass transfer parameters of both the liquid and gas phases. Based on the dimensionless parameters obtained, a correlation is proposed to calculate the mass transfer flux of acidic gases in MDEA–PZ solutions. The mass transfer flux in the reactive absorption process is modeled based on the four laws of chemical equilibrium, phase equilibrium, mass balance, and charge balance. Experimental data from the literature were used to determine the constants of the derived correlation as a function of dimensionless parameters. In the provided correlation, the effects of dimensionless parameters including film parameter, CO2 loading, ratio of diffusion coefficients in the gas–liquid phase, CO2 partial to total pressure, and film thickness ratio as well as factors such as temperature, the number of free amines in the solution, the partial pressure of CO2, on the CO2 mass transfer flux were investigated. According to the results, the absorption rate decreases with increasing CO2 loading and film parameter, and the mean absolute deviation is about 3.6%, which indicates the high accuracy of the correlation.
Petroleum Engineering
Hessam MansouriSiahgoli; Mohammad Ali Riahi; Bahare Heidari; Reza Mohebian
Abstract
It is difficult to identify the carbonate reservoirs by using conventional seismic reflection data, especially in cases where the reflection coefficient of the gas-bearing zone is close to that of the carbonate background. In such cases, the extended elastic impedance (EEI) as a seismic reconnaissance ...
Read More
It is difficult to identify the carbonate reservoirs by using conventional seismic reflection data, especially in cases where the reflection coefficient of the gas-bearing zone is close to that of the carbonate background. In such cases, the extended elastic impedance (EEI) as a seismic reconnaissance attribute with the ability to predict fluids and lithology can be used. It allows for a better distinction between seismic anomaly caused by lithology and the one caused by the fluid content. The EEI attribute extends the available reflection angles and applies different weights to the intercept and gradient values so as to extract the petrophysical properties of the rock at a specific incident angle. Using the EEI attribute, we can estimate the elastic parameters such as shear impedance; the ratio of the compressional velocity to shear velocity; Poisson’s ratio; and bulk, Lame, and shear moduli, and petrophysical properties, including porosity, clay content, and water saturation. The known reservoirs in the study area are three oil-bearing formations namely, Surmeh (Arab), Gadvan (Buwaib), and Dariyan (Shuaiba), and three gas-bearing formations, including Kangan, Dalan, and Faraghan. The Dehram group is composed of Kangan (Triassic), Dalan, and Faraghan (Permian) formations. Permian carbonates of Kangan–Dalan and its equivalent Khuff have regionally been developed as a thick carbonate sequence in the southern Persian Gulf region. In this paper, parameters 𝜆𝑝 and 𝜇𝜌 extracted from the EEI method are used to characterize a carbonate reservoir. Our results show that the EEI can highlight the difference between the reservoir and non-reservoir formation to identify the gas-bearing areas.
Petroleum Engineering
Amir Gharavi; Mohamed Hassan; Hesam Zarehparvar Ghoochaninejad; John Fianu; Michael Kenomore; Amjad Shah; James Buick
Abstract
Since the development bloom in unconventional reservoirs in North America, total organic carbon (TOC) has become a more essential parameter, as the indicator of the efficiency of these reservoirs. In this paper, by using conventional well logs and NMR log data, the TOC content of an unconventional reservoir ...
Read More
Since the development bloom in unconventional reservoirs in North America, total organic carbon (TOC) has become a more essential parameter, as the indicator of the efficiency of these reservoirs. In this paper, by using conventional well logs and NMR log data, the TOC content of an unconventional reservoir in West Africa is estimated. Passy’s, Issler’s, and Schmoker’s methods were used as indirect wireline methods to estimate TOC content, along the well paths. Afterward, NMR log data, as a direct method, was used to provide more precise calculations of TOC. Both methods showed almost similar trends, with the NMR method indicating lower values for the TOC. Then, an adjusted Schmoker equation was proposed, which showed the best fit between NMR and conventional well logs results. By using the equation, the TOC content was calculated in three other wells, where NMR data were unavailable. The results were then used to prepare a 3D model of the TOC distribution, within the reservoir.
Petroleum Engineering
Mehdi Qassamipour; Elnaz Khodapanah; Seyyed Alireza Tabatabaei-Nezhad
Abstract
Net pay thickness is defined as that portion of a reservoir which contains economically producible hydrocarbons with today’s technology, prices, and costs. This thickness is a key parameter of the volumetric calculation of in-place hydrocarbons, well test interpretation, and reservoir characterization. ...
Read More
Net pay thickness is defined as that portion of a reservoir which contains economically producible hydrocarbons with today’s technology, prices, and costs. This thickness is a key parameter of the volumetric calculation of in-place hydrocarbons, well test interpretation, and reservoir characterization. A reservoir interval is considered as net pay when it contains hydrocarbons that can flow at an economic rate. Therefore, to define net pay, cutoffs of hydrocarbon storage properties besides flow properties of reservoir rock are necessary. Frequently, petrophysical log-derived rock storage properties like porosity and water saturation are linked to core measured properties like permeability to find a relation between them. Then, by use of a fixed limiting value for permeability, log-derived properties cutoffs are determined. The basic problem of these methods is related to permeability cutoff, since in most cases there is no knowledge about it, and the permeability cutoff can differ from field to field or even well to well. A new methodology has been developed to find a logical permeability cutoff for gas reservoirs which can differ for different wells and/or fields. This technique is based on gas flow through porous media in tight rocks. Accordingly, a relationship between porosity and permeability is derived as a cutoff value at reservoir pressure and temperature, which is considered as a discriminator plot. Then, the core data of the specified reservoir are added to this plot and the data points reflecting net pay zone are identified. This technique has been applied to four real gas reservoirs in Iran and indicated acceptable results confirmed by the drill stem test (DST) and production data. The results show that the proposed procedure is less dependent on experts’ experiences and acts as a straightforward and powerful tool for the refinement of net pays. In addition, the cutoff values calculated from this method contain a scientific base supporting the main procedure.
