Petroleum Engineering
Amin Daryasafar; Mohammad FathiNasab; Giovanni Da Prat; Riyaz Kharrat
Abstract
In this paper, decline curve analysis is used for estimating different parameters of bounded naturally fractured reservoirs. This analysis technique is based on rate transient technique, and it is shown that if production rate is plotted against time on a semi-log graph, straight lines are obtained that ...
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In this paper, decline curve analysis is used for estimating different parameters of bounded naturally fractured reservoirs. This analysis technique is based on rate transient technique, and it is shown that if production rate is plotted against time on a semi-log graph, straight lines are obtained that can be used to determine important parameters of the closed fractured reservoirs. The equations are based on Warren and Root model. The comparison between the results of this technique and those of the conventional methods confirms its high proficiency in transient well testing. It should be noted that in conventional decline curve methods, parameters such as interporosity flow parameter and storage capacity ratio must be first obtained by previous methods like the build-up analysis, but in the proposed method all the main reservoir parameters can be calculated directly, which is one of the advantages of this method. This paper focuses on the interpretation of rate tests, and the starting points and slopes of straight lines are utilized with proper equations to solve directly for various properties. The main important aspect of the presented method is its accuracy since analytical solutions are used for calculating reservoir parameters.
Petroleum Engineering
Mohsen Seidmohammadi; Eghbal Sahraei; Behrouz Bayati
Abstract
Currently available polymers as a component of in-situ gels are unsuitable for treating high-temperature/high-salinity reservoirs due to their chemical and thermal degradation. In this study, a new copolymer-based gel system including high molecular weight nanostructured polymers (NSPs) was developed ...
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Currently available polymers as a component of in-situ gels are unsuitable for treating high-temperature/high-salinity reservoirs due to their chemical and thermal degradation. In this study, a new copolymer-based gel system including high molecular weight nanostructured polymers (NSPs) was developed to address the excessive water production problem in reservoirs under harsh conditions. The stability of conventional polymer systems and NSPs was investigated under conditions of 40 days aging at 87000 ppm salinity and 90 °C. Then, gelation time optimization of gel systems composed of NSPs and chromium (III) acetate was performed with regards to the effect of copolymer concentration and copolymer/cross-linker ratio and their interactions during the gelation time. The central composite approach was used to design experiments and build a mathematical model. The analysis of variance (ANOVA) was used to estimate the deviation of the model predictions from the data. The results of stability analysis demonstrated the advantages of NSPs over conventional polymers by a viscosity reduction of 69, 36, and 18% for Flopaam3310, AN105, and NSPs respectively. The model developed for the prediction of gelation time of NSPs gel was significant at a confidence level of 98.6% against the test data. Moreover, it was found that gelation time became longer with a decrease in copolymer concentrations and/or increase in copolymer/cross-linker ratio.
Petroleum Engineering
Yavar Karimi; Ali Reza Solaimany Nazar
Abstract
The influences of several operating factors on the viscosity of the Isfahan refinery waxy crude oil sample are studied through conducting some rheological shear rotational tests. The Taguchi design method is adopted to determine the impact of factors such as shear rate, temperature, cooling rate, wax ...
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The influences of several operating factors on the viscosity of the Isfahan refinery waxy crude oil sample are studied through conducting some rheological shear rotational tests. The Taguchi design method is adopted to determine the impact of factors such as shear rate, temperature, cooling rate, wax content, and asphaltene content on the viscosity of the waxy crude oil. The results show that temperature with a contribution of 53.61% is the most influential factor. The wax content, shear rate, and asphaltene content have a contribution of 20.86, 14.75, and 3.11% respectively. The cooling rate does not have a statistically significant effect on the viscosity. The results of the rheological oscillatory tests confirm that the temperature and wax content change the viscoelastic properties of the waxy crude oil completely. An increase in the wax content from 12 to 22 wt.% raises the wax appearance temperature (WAT) from 19.1 to 34.9 °C and improves the gel point from 13 to 34.1 °C. By decreasing the temperature or increasing wax content, the viscoelastic nature of the oil sample changes from a viscoelastic fluid to a viscoelastic solid.
Petroleum Engineering
Ali Moazami Goodarzi; Arman Darvish Sarvestani; Ali Hadipour
Abstract
Nowadays, the increasing demand for energy in the world is one of the main concerns for energy supply. In fact, the required energy can be obtained by increasing the production rate of fossil fuels such as oil and natural gas. However, improving the efficiency of the equipment and facilities might have ...
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Nowadays, the increasing demand for energy in the world is one of the main concerns for energy supply. In fact, the required energy can be obtained by increasing the production rate of fossil fuels such as oil and natural gas. However, improving the efficiency of the equipment and facilities might have a significant impact on production from hydrocarbon resources. With respect to this subject, the optimization of separation facilities will be a simple and economic choice to increase the amount of the liquid obtained from production units all over the world. One of the parameters which have a noticeable effect on the yield of the production units is the separator pressure. Also, there are other factors such as heptane plus fraction properties, well head pressure, and ambient temperature which can change the optimum separator conditions. In this study, the influence of crude oil properties on the number of stages and pressure of each separator is investigated. The result shows that the most important property of the feed which has the greatest influence on the conditions of separators is the percentage of heptane plus fraction in crude oil. Therefore, a method for the estimation of the number of separators based on the percentage of C7+ component is developed. Moreover, the threshold of heptane plus fraction for selecting the optimum number of separator stages was observed to be around 30% in the feed composition. Hence, three separators and a stock tank can separate samples with a C7+ molar fraction lower than 30%, but two separators and a stock tank are needed for samples with a heptane plus fraction higher than 30%. Finally, the results indicate an increase of about 1.3% in the oil production for the new optimization method compared to the constant-ratio method.
Petroleum Engineering
Mehrbod khalatbari; Mohammadreza Kamali; Mehran Arian; Buyuk Ghorbani
Abstract
The Khaviz oil field located in Dezful embayment is one of Iran’s southwest oil fields. In this study, a total of 28 cutting samples from Kazhdumi formation (well No. KZ1, Khaviz oil field) were subject to geochemical investigation using Rock-Eval pyrolysis for the first time. The results of pyrolysis ...
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The Khaviz oil field located in Dezful embayment is one of Iran’s southwest oil fields. In this study, a total of 28 cutting samples from Kazhdumi formation (well No. KZ1, Khaviz oil field) were subject to geochemical investigation using Rock-Eval pyrolysis for the first time. The results of pyrolysis indicated that Kazhdumi source rock has significant hydrocarbon production potentiality and already entered the oil generation window. As inferred from the diagram of OI versus HI, Kazhdumi source rock contains organic matter type II kerogen deposited in paralic environment with anoxic to suboxic conditions. Using the diagram of S2 versus TOC, the absorbed carbon content, neutral carbon, and active carbon were calculated to be 0.42, 0.39, and 2.43 wt.% respectively.
Petroleum Engineering
Shahin Kord; Omid Ourahmadi; Arman Namaee-Ghasemi
Abstract
Production strategy from a hydrocarbon reservoir plays an important role in optimal field development in the sense of maximizing oil recovery and economic profits. To this end, self-adapting optimization algorithms are necessary due to the great number of variables and the excessive time required for ...
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Production strategy from a hydrocarbon reservoir plays an important role in optimal field development in the sense of maximizing oil recovery and economic profits. To this end, self-adapting optimization algorithms are necessary due to the great number of variables and the excessive time required for exhaustive simulation runs. Thus, this paper utilizes genetic algorithm (GA), and the objective function is defined as net present value (NPV). After developing a suitable program code and coupling it with a commercial simulator, the accuracy of the code was ensured using a synthetic reservoir. Afterward, the program was applied to an Iranian southwest oil reservoir in order to attain the optimum scenario for primary and secondary production. Different hybrid water/gas injection scenarios were studied, and the type of wells, the number of wells, well coordination/location, and the flow rate (production/injection) of each well were optimized. The results from these scenarios were compared, and simultaneous water and gas (SWAG) injection was found to have the highest overall profit representing an NPV of about 28.1 billion dollars. The application of automated optimization procedures gives rise to the possibility of including additional decision variables with less time consumption, and thus pushing the scopes of optimization projects even further.
Petroleum Engineering
Majid Alipour; Bahram Alizadeh; Scott Ramos; Behzad Khani; Shohreh Mirzaie
Abstract
Chemometric methods can enhance geochemical interpretations, especially when working with large datasets. With this aim, exploratory hierarchical cluster analysis (HCA) and principal component analysis (PCA) methods are used herein to study the bulk pyrolysis parameters of 534 samples from the Persian ...
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Chemometric methods can enhance geochemical interpretations, especially when working with large datasets. With this aim, exploratory hierarchical cluster analysis (HCA) and principal component analysis (PCA) methods are used herein to study the bulk pyrolysis parameters of 534 samples from the Persian Gulf basin. These methods are powerful techniques for identifying the patterns of variations in multivariate datasets and reducing their dimensionality. By adopting a “divide-and-conquer” approach, the existing dataset could be separated into sample groupings at family and subfamily levels. The geochemical characteristics of each category were defined based on loadings and scores plots. This procedure greatly assisted the identification of key source rock levels in the stratigraphic column of the study area and highlighted the future research needs for source rock analysis in the Persian Gulf basin.
Petroleum Engineering
Ahmed Zoeir; Mohammad Chahardowli; Mohammad Simjoo
Abstract
Fractured carbonate reservoirs account for 25% of world’s total oil resources and for 90% of Iranian oil reserves. Since calcite and dolomite minerals are oil wet, gas oil gravity drainage (GOGD) is known as the most influencing production mechanism. The most important issue within gas injection ...
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Fractured carbonate reservoirs account for 25% of world’s total oil resources and for 90% of Iranian oil reserves. Since calcite and dolomite minerals are oil wet, gas oil gravity drainage (GOGD) is known as the most influencing production mechanism. The most important issue within gas injection into fractured media is the channeling problem which makes the efficiency of gas injection process extremely low. As a solution, foam is used to change the mobility ratio, to increase volumetric sweep efficiency, and to overcome the fingering problem. In this work, we inspected three main influencing mechanisms that affect oil extraction from matrix, namely foam/oil gravity drainage, viscous pressure drop due to foam flow in fractures, and foaming agent diffusion from fractures into the matrixes. Foam injection simulations were performed using CMG STARS 2015, on a single matrix unit model and on some vertical cross section models. A number of sensitivity analyses were performed on foam strength, injection rate, fracture and matrix properties, matrix heights, and the initial oil saturation within matrixes. The results show that the roles of the mass transfer of the foaming agent and viscous pressure drop are significant, especially when matrix average heights are small. Moreover, the mechanism for viscous pressure drop remains unchanged, which continues to aid oil extraction from matrixes while the other two mechanisms weaken with time.
Petroleum Engineering
Ali Nemati Kharat; Ali akbar Ghaffari
Abstract
The aim of this research was to produce a convenient additive for enhancing the properties, especially the fluid loss, of oil well cement slurries. In this regard, a variety of drilling/cementing chemical additives known as fluid loss controllers were prepared through derivatization and chemical modification ...
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The aim of this research was to produce a convenient additive for enhancing the properties, especially the fluid loss, of oil well cement slurries. In this regard, a variety of drilling/cementing chemical additives known as fluid loss controllers were prepared through derivatization and chemical modification of lignite. Lignite-based graft copolymers were synthesized using different groups of acrylic monomers via aqueous the free radical polymerization method. Then, it was allowed to react with sulfomethylating agents to enhance its water solubility. Subsequently, a comparative sulfomethylated lignite was prepared and employed as the backbone in the free radical polymerization. ATR-FTIR and elemental analyses were performed to demonstrate the structures of the fluid loss controller and incorporated elements. The performance of these additives in improving the properties of oil well cement slurries was investigated through analyzing the quality of fluid loss controller in saline saturated slurries. Under similar desired well conditions, i.e. a compressive strength of 800-1100 psi, a thickening time of 400 minutes, and a viscosity of 25 cP, a fluid loss below 130 ml API was obtained. The best standard performance was assigned to the cement slurry which employed sulfomethylated lignite graft copolymer.
Petroleum Engineering
Naser Akhlaghi; Siavash Riahi
Abstract
One of the tertiary methods for enhanced oil recovery (EOR) is the injection of chemicals into oil reservoirs, and surface active agents (surfactants) are among the most used chemicals. Surfactants lead to increased oil production by decreasing interfacial tension (IFT) between oil and the injected water ...
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One of the tertiary methods for enhanced oil recovery (EOR) is the injection of chemicals into oil reservoirs, and surface active agents (surfactants) are among the most used chemicals. Surfactants lead to increased oil production by decreasing interfacial tension (IFT) between oil and the injected water and to the wettability alteration of the oil reservoir rock. Since surfactants are predominantly expensive materials, it is required to consider an appropriate and high-performance plan for project economics when they are injected into oil reservoirs. One of the operational issues in surfactant flooding is the critical micelle concentration (CMC), which is usually achieved by the injection of surfactant at concentrations higher than CMC. Therefore, the lower the CMC is, the lower the amount of the material needed to be injected into the reservoir becomes, so it will help to economize the project. The salinity of the aqueous phase is a factor affecting the CMC, and with its optimal design, it can reduce the CMC. In this study, the variations of Triton X-100 CMC’s as a nonionic surfactant were measured by altering the concentration of three salts with divalent ions (CaCl2, MgCl2, and Na2SO4) and a single-capacity ion salt (NaCl), as the predominant salts in the porous medium of oil reservoirs, using surface tension (ST) method at ambient temperature and pressure. Each of these salts was dissolved at three concentrations of 0.1, 0.5, and 1 wt.% in distilled water containing specific concentrations of surfactant, and the surfactant CMC in the presence of these salt concentrations was measured. The results showed that increasing the concentration of each salt resulted in a decrease in the CMC, and, in the studied salts, NaCl produced the lowest CMC.
Petroleum Engineering
Mohammad Abdideh; Yaghob Hamid
Abstract
Cap rocks are dams which can prevent the upward movement of hydrocarbons. They have disparities and weaknesses including discontinuities, crushed areas, and faults. Gas injection is an effective mechanism for oil recovery and pore pressure. With increasing pore pressure, normal stress is reduced, and ...
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Cap rocks are dams which can prevent the upward movement of hydrocarbons. They have disparities and weaknesses including discontinuities, crushed areas, and faults. Gas injection is an effective mechanism for oil recovery and pore pressure. With increasing pore pressure, normal stress is reduced, and the integrity of impermeable boundaries (cap rock, fault, etc.) becomes instable. A successful strategy for reservoir development is the inevitable necessity of conducting geomechanical studies and modeling the reservoir. The construction of a comprehensive geomechanical model, including the stress state is a function of depth (direction and amount), physical properties of the reservoir rock and its formations (rock resistance and elastic moduli), pore pressure estimation, and description and distribution of fractures and faults. In this work, analytical and numerical methods have been used in geomechanical modeling, and the data used for modeling and petrophysical information are downhole tests. The geomechanical modeling of gas injection into the reservoir and, simultaneously, the operation of Asmari reservoir and Marun oilfield cap rock in the southwest of Iran were carried out. The threshold of reactivating faults and the critical pressure of induced fracture were calculated, and the results were presented as analytical and numerical models. Moreover, in addition to analyzing the stress field at depths, the resistance parameters of the formations were determined. The results showed that the most changes and instabilities were around the wellheads, fractures, and the edges of the field.
Petroleum Engineering
Iman Jafari; Mohsen Masihi; Masoud Nasiri Zarandi
Abstract
Cocurrent spontaneous imbibition (COCSI) of an aqueous phase into matrix blocks arising from capillary forces is an important mechanism for petroleum recovery from fractured petroleum reservoirs. In this work, the modeling of countercurrent imbibition is used to develop the appropriate scaling equations. ...
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Cocurrent spontaneous imbibition (COCSI) of an aqueous phase into matrix blocks arising from capillary forces is an important mechanism for petroleum recovery from fractured petroleum reservoirs. In this work, the modeling of countercurrent imbibition is used to develop the appropriate scaling equations. Considering the imbibition process and the water and oil movement respectively as the wet phase and the non-wet phase in a block saturated by oil and surrounded by two vertical fractures full of water, a differential equation having partial and nonlinear derivatives is introduced using Darcy and mass balance equations. On the other hand, as there is no analytical solution for this equation, a new equation is introduced by considering the different intervals of the wet and non-wet phase viscosity and by selecting the best suitable functions for relative permeability and capillary pressure. Considering the boundary conditions governing the countercurrent imbibition, an analytical solution (equation) is developed. Finally, the developed equation is validated. The results of this research can be very important for a better understanding of the imbibition process and the water and oil movement in the fractured environments.
Petroleum Engineering
Yaser Ahmadi; Babak Aminshahidy
Abstract
This paper addressed the application of new hydrophobic synthesized calcium oxide (CaO) and silicon dioxide (SiO2) nanofluids to low permeability carbonate porous media. Crude oil and plugs were selected from one of oil reservoirs in the west of Iran. The main goal of this paper is comparing the results ...
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This paper addressed the application of new hydrophobic synthesized calcium oxide (CaO) and silicon dioxide (SiO2) nanofluids to low permeability carbonate porous media. Crude oil and plugs were selected from one of oil reservoirs in the west of Iran. The main goal of this paper is comparing the results of improving water-oil relative permeability parameters in low permeability plugs of carbonate cores in the presence of new synthesized CaO and SiO2 nanofluids. All the experiments were performed at a temperature of 40 °C and at a nanoparticle concentration of 45 ppm. The experimental approaches were designed into two main steps: 1) the effects of both nanoparticles on the changes in interfacial tension (between oil and brine) and oil viscosity 2) the effects of both nanoparticles on wettability (qualitatively) and relative permeability parameters. SiO2 and CaO decreased interfacial tension from 46.414 mN/m to 41.772 mN/m and 32.860 mN/m respectively. Moreover, SiO2 and CaO decreased oil viscosity from 9.90 cP to 8.61 cP and 8.01 cP respectively. Based on the obtained results in the core flood experiments, although CaO and SiO2 nanofluids decreased effective water permeability, effective oil permeability and ultimate oil recovery increased. Moreover, it was seen that the CaO nanofluid improved oil flow in carbonate cores more than the commercial SiO2 flooding. Finally, it was seen that both nanoparticles change the wettability from oil-wet to water-wet (qualitatively).
Petroleum Engineering
Hojatallah Koraee; Hadi Eskandari; Iman Danaee
Abstract
Corrosion results in hazardous and expensive damage to pipelines, vehicles, water and wastewater systems, and even home appliances. One of the most extensively practical methods for protecting metals and alloys against corrosion is to use organic inhibitors. The inhibition capability of 2-Mercaptobenzothiazole ...
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Corrosion results in hazardous and expensive damage to pipelines, vehicles, water and wastewater systems, and even home appliances. One of the most extensively practical methods for protecting metals and alloys against corrosion is to use organic inhibitors. The inhibition capability of 2-Mercaptobenzothiazole (2-MBT) against the corrosion of carbon steel in a 2 M NaCl solution was examined by Tafel polarization. By using 2-Mercaptobenzothiazole both the cathodic and anodic reactions are delayed through chemical and physical adsorption and blocking the active corrosion sites. Based on the polarization curves, it was indicated that by increasing the inhibitor concentration, the inhibition efficiency increases up to 70% at room temperature, and it improves at higher temperatures. The adsorption of 2-Mercaptobenzothiazole was based on the Langmuir adsorption isotherm. The enthalpies of activation were determined to be around +50 kJ.mol-1. The endothermic nature of the steel dissolution procedure is reflected by the positive symbols of the enthalpies (ΔH) of activation process. The determined values range from -32.69 to -35.81 kJ.mol-1, which shows both electrostatic adsorption and the chemisorption of the adsorption mechanism. The calculated entropy of adsorption was 78 J.mol-1.K-1 indicating the increment in the solvent entropy and a more positive water desorption entropy.
Petroleum Engineering
Arezou Jafari; Peyman Sadirli; Reza Gharibshahi; Esmaeel Kazemi Tooseh; Masoud Samivand; Ali Teymouri
Abstract
Natural gas storage process in aquifer, due to fluid flow behavior of gas and water in the porous medium and because of their contact with each other under reservoir conditions, faces several challenges. Therefore, there should be a clear understanding of the injected gas behavior before and after the ...
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Natural gas storage process in aquifer, due to fluid flow behavior of gas and water in the porous medium and because of their contact with each other under reservoir conditions, faces several challenges. Therefore, there should be a clear understanding of the injected gas behavior before and after the injection into the reservoir. This research simulates the natural gas storage in aquifer by using Eclipse 300 software. For this purpose, a core sample was considered as the porous medium for gas injection, and a composition of natural gas was injected into the core in different conditions. Moreover, by using Plackett-Burman method, all of the factors affected in this process were screened, and finally four main significant parameters, including the flow rate of injected gas, permeability, pressure, and irreducible water saturation were selected for designing a design of experiments (DOE) plan. Response surface method (RSM) is one of the best methods of experimental design used for optimizing the process and finding the best combination of parameters to have a high stored gas volume and a high recovered gas volume. The simulation includes 28 runs with four considered parameters, and the output is the recovered gas, which in turn is vital for the process accomplishment. Sensitivity analysis and grid independency test were checked. To this end, three grids with different number of cells in x-direction were generated, and by analyzing the results of gas saturation in the porous medium for each model, a grid with 11250 cells (50 elements in x-direction and 15 elements in y- and z-directions) was then chosen as the main grid. Uncertainty analysis and the validation of numerical simulations were carried out, and good agreement was observed between the numerical results and experimental data. In addition, the numerical results showed that the flow rate of the injected gas had a significant impact on the process in comparison with other parameters. Furthermore, increasing permeability and decreasing pressure and irreducible water saturation raise the amount of trapped gas in aquifers. Therefore, for having the maximum stored gas volume and a high recovered gas volume, the best combination of parameters is a high gas injection flow rate (0.9 cc/min), high permeability (1.54 md), a low pressure (2254 psi), and irreducible water saturation. (0.46). Finally, in a natural gas storage operation in an aquifer, both rock properties and operational parameters play important roles, and they should be optimized in order to have the highest amount of stored gas.
Petroleum Engineering
Sadegh Saffarzadeh; Abbdolrahim Javaherian; Hossein Hasani; Maryam Sadri
Abstract
Seismic modeling aids the geophysicists to have a better understanding of the subsurface image before the seismic acquisition, processing, and interpretation. In this regard, seismic survey modeling is employed to make a model close to the real structure and to obtain very realistic synthetic seismic ...
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Seismic modeling aids the geophysicists to have a better understanding of the subsurface image before the seismic acquisition, processing, and interpretation. In this regard, seismic survey modeling is employed to make a model close to the real structure and to obtain very realistic synthetic seismic data. The objective of this study is to analyze the resolution and illumination of the fault by designing appropriate 3D seismic survey parameters. The ray-based seismic modeling was built using 2D seismic data, geological reports, and the well logs in one of the oil fields in the southwest of Iran. A pre-stack depth migration simulator was used to evaluate the survey geometry on the resulting seismic image. The results proved that a survey designer could improve the image of the target in a seismic section by applying the ray-based analyses, with respect to illumination and resolution studies.
Petroleum Engineering
Mostafa Zare; Abbdolrahim Javaherian; Mehdi Shabani
Abstract
The aim of seismic inversion is mapping all of the subsurface structures from seismic data. Due to the band-limited nature of the seismic data, it is difficult to find a unique solution for seismic inversion. Deterministic methods of seismic inversion are based on try and error techniques and provide ...
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The aim of seismic inversion is mapping all of the subsurface structures from seismic data. Due to the band-limited nature of the seismic data, it is difficult to find a unique solution for seismic inversion. Deterministic methods of seismic inversion are based on try and error techniques and provide a smooth map of elastic properties, while stochastic methods produce high-resolution maps of elastic properties with the same probability. The current paper studies a stochastic method of seismic inversion which was applied to one of the Persian Gulf oilfields. Joint posterior distribution of elastic properties was calculated using Bayesian principle; then a sequential Gaussian simulation technique was performed to decompose the global probability function of elastic properties into some local probability functions at each trace location. The sampling of the local probability functions was performed, and two hundred realizations of the elastic properties were generated. The results of the stochastic inversion were found to be capable of modeling heterogeneities of the reservoir. The generated realizations provided the possibility to uncertainties assessment by calculating the variance of the elastic properties. It was found out that the uncertainty increased in locations far away from the well. Moreover, stochastic inversion, unlike deterministic one, was found to be capable of detecting thin beds (3.5 to 5.7 m) embedded within the reservoir.
Petroleum Engineering
Jaber Azizi; Seyed Reza Shadizadeh; Abbas Khaksar Manshad; Naghi Jadidi
Abstract
Water flooding is one of the most influential methods for pressure maintenance and enhanced oil recovery. However, water flooding is likely to develop the formation of oilfield scale. Scale formation in reservoirs, due to the mixing of injection water and formation water, could cause formation damage ...
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Water flooding is one of the most influential methods for pressure maintenance and enhanced oil recovery. However, water flooding is likely to develop the formation of oilfield scale. Scale formation in reservoirs, due to the mixing of injection water and formation water, could cause formation damage and production limit. Therefore, it is necessary to simulate the compatibility of brine and injection water. Scale prediction is performed using many thermodynamic and/or kinetic based models. In this study, simulations with speciation (ion pairing) are studied, which is a thermodynamic based tool. The utilization of reservoir conditions, formation water analysis, and sea water analysis as the inputs in this method resulted to the accurate prediction of potential scales. In this study, the factors impacting on the scale potential such as pH, temperature, and mixing ratio were also investigated. The obtained results showed that calcite and aragonite were the major scale potential to precipitate. Finally, the results illustrated the important effect of pH and temperature on different scales formation.
Petroleum Engineering
Ali Daghaieghi; Nima Mokhtarzadeh
Abstract
Drilling industry and its technical services are among the complex and advanced technology-based industries in the cycle of oil exploration and production. In this regard, the logging services role as one of the pillars of technical services is very important due to technological complexity and the importance ...
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Drilling industry and its technical services are among the complex and advanced technology-based industries in the cycle of oil exploration and production. In this regard, the logging services role as one of the pillars of technical services is very important due to technological complexity and the importance of the results in the evaluation of oil and gas reservoirs. The complexity had caused small and medium companies in Iran not to be able to produce logging equipment by themselves due to financial and scientific constraints. Through the review of the articles and books written on this subject, this research has studied the factors affecting success in technology acquisition and then has categorized them in five dimensions as technological, technical, market, strategic, and financial factors. Next, through exploratory interviews with experts and theme analysis, the factors having the greatest impact on the acquisition of logging equipment technology have been identified and their opinion on various proposed methods in scientific resources for the acquisition of technology have been obtained. Several published methods have been reviewed; during interviews, some major effective characteristics were introduced by the experts, which could not satisfy existing methods or some principal dimensions were ignored. The results of the research and the case study of National Iranian Drilling Company show that the managed innovation network is the most appropriate method for the acquisition of the above mentioned technology for the National Iranian Drilling Company.
Petroleum Engineering
Abdolah Golkari; Masoud Riazi; Amin Avazpour
Abstract
To provide supplementary oil recovery after the primary and secondary processes, enhanced oil recovery (EOR) techniques are introduced. Carbonated water injection (CWI) as an EOR method can improve sweep efficiency and the risk of gas leakage. On the other hand, the interfacial tension (IFT) is one of ...
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To provide supplementary oil recovery after the primary and secondary processes, enhanced oil recovery (EOR) techniques are introduced. Carbonated water injection (CWI) as an EOR method can improve sweep efficiency and the risk of gas leakage. On the other hand, the interfacial tension (IFT) is one of the key factors which can affect fluid displacement during the process of CWI greatly. Therefore, the analysis of the IFT on an oil-carbonated water-CO2 system is vital. In this paper, the interfacial interactions of binary systems of asphaltenic crude oil (ACO), carbon dioxide (CO2), and carbonated water (CW) at different pressures and at two temperatures of 40 °C and 50 °C and their effects on the oil spreading in the water phase in the presence of gas are experimentally investigated. The IFT measurements were performed by axisymmetric drop shape analysis (ADSA) technique for the pendant/rising oil drop case. It is found out that the equilibrium interfacial tension (EIFT) of the two systems of crude oil-CO2 and water-CO2 is reduced almost linearly with pressure but increased with temperature. Moreover, the pressure has an increasing and decreasing effect on the water-oil and CW-oil IFT’s respectively. However, temperature has a reverse effect for the both systems. Spreading coefficient (SC) concept would help better understand the oil recovery mechanisms and potential. The results show that SC curve has a minimum point value as a specific pressure, which increases with temperature. The presence of CO2 in the water phase could strongly affect the oil spreading phenomenon through which oil recovery could be significantly enhanced.
Petroleum Engineering
Meysam Dabiri-Atashbeyk; Mehdi Koolivand-salooki; Morteza Esfandyari; Mohsen Koulivand
Abstract
Reservoir characterization and asset management require comprehensive information about formation fluids. In fact, it is not possible to find accurate solutions to many petroleum engineering problems without having accurate pressure-volume-temperature (PVT) data. Traditionally, fluid information has ...
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Reservoir characterization and asset management require comprehensive information about formation fluids. In fact, it is not possible to find accurate solutions to many petroleum engineering problems without having accurate pressure-volume-temperature (PVT) data. Traditionally, fluid information has been obtained by capturing samples and then by measuring the PVT properties in a laboratory. In recent years, neural network has been applied to a large number of petroleum engineering problems. In this paper, a multi-layer perception neural network and radial basis function network (both optimized by a genetic algorithm) were used to evaluate the dead oil viscosity of crude oil, and it was found out that the estimated dead oil viscosity by the multi-layer perception neural network was more accurate than the one obtained by radial basis function network.
Petroleum Engineering
Majid Alipour; Bahram Alizadeh; Ali Chehrazi
Abstract
Commercial hydrocarbon discoveries in the Cretaceous of the southern Persian Gulf basin provide direct evidence that there is an effective petroleum system associated with the Cretaceous series. The revised models of thermal maturity in this region are needed to investigate lateral and stratigraphic ...
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Commercial hydrocarbon discoveries in the Cretaceous of the southern Persian Gulf basin provide direct evidence that there is an effective petroleum system associated with the Cretaceous series. The revised models of thermal maturity in this region are needed to investigate lateral and stratigraphic variations of thermal maturity, which have not so far been addressed in detail for this part of the Persian Gulf. Such thermal maturity models are required to delineate the existing play assessment risks and to predict properties in more deeply buried undrilled sections. This study uses two dimensional basin modeling techniques to reconstruct maturity evolution of the Cenomanian Middle Sarvak source rock, presumably the most likely source for these hydrocarbons. The results indicate that an estimated 900 meter difference in the depth of burial between the southeastern high and the adjacent trough tends to be translated into noticeable variations at both temperature (135 °C versus 162 °C) and vitrinite reflectance (0.91% versus 1.35%). Since the organic matter in the mentioned source rock is of reactive type II, these could cause a shift of about 18 million years in the onset of hydrocarbon generation over respective areas.
Petroleum Engineering
Milad Karimian; Mahin Schaffie; Mohammad Hassan Fazaelipoor
Abstract
An efficient design of in situ combustion depends on accurate kinetic modeling of the crude oil oxidation. The kinetic triplet of the oxidation reactions of a heavy oil sample was investigated. Once the kinetic triplet is known, the kinetic equation would be deconvolved. The crude oil sample was obtained ...
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An efficient design of in situ combustion depends on accurate kinetic modeling of the crude oil oxidation. The kinetic triplet of the oxidation reactions of a heavy oil sample was investigated. Once the kinetic triplet is known, the kinetic equation would be deconvolved. The crude oil sample was obtained from Kuh-E-Mond reservoir, located in the southwest of Iran. The samples were analyzed using differential scanning calorimetry (DSC) at atmospheric pressure, in a temperature range of 297- 973 K, and at four different heating rates. Three isoconversional kinetic models were used to obtain a variation of Arrhenius parameters during the course of the high temperature oxidation reaction. The activation energy (Eα) and the pre-exponential factor (A) were obtained at different conversions. Having Arrhenius parameters, the conversion function, f(α), was estimated using an advanced master plot method. It was observed that f(α) follows the Avrami–Erofeev (An) model with n=3. Furthermore, the parameters of truncated Sestak–Berggren (SB) reaction model were obtained. SB fits fairly better than A3 to the experimental data. According to the results, a change in the heating rate does not considerably vary the reaction model.
Petroleum Engineering
Reza Mohebian; Mohammad Ali Riahi; Ali Kadkhodaie-Ilkhchi
Abstract
Intelligent reservoir characterization using seismic attributes and hydraulic flow units has a vital role in the description of oil and gas traps. The predicted model allows an accurate understanding of the reservoir quality, especially at the un-cored well location. This study was conducted in two major ...
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Intelligent reservoir characterization using seismic attributes and hydraulic flow units has a vital role in the description of oil and gas traps. The predicted model allows an accurate understanding of the reservoir quality, especially at the un-cored well location. This study was conducted in two major steps. In the first step, the survey compared different intelligent techniques to discover an optimum relationship between well logs and seismic data. For this purpose, three intelligent systems, including probabilistic neural network (PNN),fuzzy logic (FL), and adaptive neuro-fuzzy inference systems (ANFIS)were usedto predict flow zone index (FZI). Well derived FZI logs from three wells were employed to estimate intelligent models in the Arab (Surmeh) reservoir. The validation of the produced models was examined by another well. Optimal seismic attributes for the estimation of FZI include acoustic impedance, integrated absolute amplitude, and average frequency. The results revealed that the ANFIS method performed better than the other systems and showed a remarkable reduction in the measured errors. In the second part of the study, the FZI 3D model was created by using the ANFIS system.The integrated approach introduced in the current survey illustrated that the extracted flow units from intelligent models compromise well with well-logs. Based on the results obtained, the intelligent systems are powerful techniques to predict flow units from seismic data (seismic attributes) for distant well location. Finally, it was shown that ANFIS method was efficient in highlighting high and low-quality flow units in the Arab (Surmeh) reservoir, the Iranian offshore gas field.
Petroleum Engineering
Abolfazl Hashemi; Seyed Reza Shadizadeh
Abstract
Hydrochloric acidizing is a routine operation in oil fields to reduce the mechanical skin. In this paper, practical acidizing in a typical carbonate oil reservoir located in the southwest of Iran is practiced, which shows an unexpected improvement after acidizing. To understand the acidizing effect on ...
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Hydrochloric acidizing is a routine operation in oil fields to reduce the mechanical skin. In this paper, practical acidizing in a typical carbonate oil reservoir located in the southwest of Iran is practiced, which shows an unexpected improvement after acidizing. To understand the acidizing effect on reservoir rock, the formation rock is analyzed on different scales. An acidizing laboratory test is also carried out on formation core samples to understand the acidizing performance. The results show that the main feature of this reservoir is its dominated secondary porosity and its special pattern of distribution. Practically, this porosity percolation has caused high mechanical skin during drilling and a large productivity improvement after acidizing. The acidizing increased the ultimate recovery of the reservoir with existing wells and prolonged the production plateau.
