Fiber optic sensor systems have been in the oilfield for a number of years now, however, they have had many shortcomings, including high price points, which have prevented widespread adoption. We can integrate fiber optic sensors into oil and gas companies products and processes and take advantage both technically and economically of the ever more rapid advances in technology. We can design all sorts of fiber optic sensors that cover various sections of petroleum industry operations. Most of the researches have been in this part of technology since that is where most of the applications are. However, the other types of sensors have also developed as well. Most of the fiber optical sensors have just one or perhaps a few detectors, but some high-resolution imaging systems with large detector element arrays have also developed. Some fiber optical sensors are frequently incorporated as components in larger products. They are also used independently in process control and other types of applications in the petroleum industry. This paper describes various aspects of fiber optic sensors and their applications and addresses their role in the petroleum industry.

The presented oil sensor system for the continuous, online measurement of the wear in industrial gears, turbines, generators, transformers and hydraulic systems. The detection of change is much earlier than existing technologies such as particle counting, vibration measurement or recording temperature. Thus, targeted, corrective procedures and/or maintenance can be carried out before actual damage occurs. Efficient machine utilization, accurately timed preventive maintenance, a reduction of downtime and an increased service life and can all be achieved.
The oil sensor system measures the components of the complex impedances X of the oils, in particular, the electrical conductivity, the relative dielectric constant and the oil temperature. All values are determined independently from each other.
Inorganic compounds occur at contact surfaces from the wear of parts, broken oil molecules, acids or oil soaps. These all lead to an increase in the electrical conductivity, which correlates directly with the wear. In oils containing additives, changes in dielectric constant infer the chemical breakdown of additives. A reduction in the lubricating ability of the oils, the determination of impurities, the continuous evaluation of the wear of bearings and gears and the oil aging all together follow the holistic approach of real-time monitoring of changes in the oil-machine system. By long-term monitoring and continuous analysis of the oil quality, it is possible to identify the optimal time interval of the next oil exchange – condition based. This results in enormous cost reduction, when the oil is still stable and fully functional.
An application example from the wind energy sector will be presented in detail to show the potential of the measurement system and advanced data treatment: from the processed data the identification of critical operation conditions, the determination of the next oil change and a health indication of the wind turbine is possible.

One of the most important parameters in the modeling of oil and gas reservoirs is relative permeability. Relative Permeability is a function of wetting/non wetting phase saturations and the mineralogy of reservoir rock relative to the pore size distribution. In this paper, we discuss experimental measuring of relative permeability for a reservoir rock of a formation of an oil field for two-phase flow (Brine and Kerosene). Relative permeability values will be determined at each water saturation value by injection brine and kerosene in core flood apparatus. Then relevant relative permeability curves for each phase will be plotted as a function of water saturation value and then, wetting ability condition of the samples will be recognized through these curves. Finally, we try to find a correlation for determination the relative permeability of this oil field.

Solid oxide fuel cells have always been focused on highly efficient converting of chemical energy of solid fuels – from coal to electrical energy [1. Technically, this problem is solved by using a liquid anode based on salt melt and the introduction of powder into the melt of solid fuels – into coal. These fuel cells for direct oxidation of coal are usually called - Direct Carbon Fuel Cells (DCFC). Laboratory tests for 1200 h showed the possibility of obtaining at temperatures of 800 - 950OC power density of more than 300 mW/cm2. The concept of the multi-element battery was experimentally tested. As a result of this work, it has been shown that the power plant for the direct oxidation of coal in solid oxide fuel cells - DCFC can be implemented with the specific characteristics of up to 20 kWh / l and with an efficiency of 70%.

This paper presents results of a study conducted to evaluate changes in oil properties of an oilfield due to gas injection and their effects on production from this field while under gas injection. In this work, effects of gas injection on reservoir fluid phase behavior of a fractured oil reservoir have been investigated. For this purpose, first, the properties of primary reservoir fluid have been studied. Then, by using software, a suitable equation of state for prediction the behavior of reservoir fluid was selected. Then, properties of current reservoir fluid which were achieved by PVT tests have been studied. Phase behavior of current reservoir fluid was compared with phase behavior of primary reservoir fluid. It was found that phase behavior of reservoir fluid has been changed due to gas injection into this reservoir. After evaluating oil properties of this field, we describe how these properties affect reservoir quality and EOR strategy.

A variety of oil recovery methods have been developed and applied to mature and depleted reservoirs in order to improve the efficiency. Microwave radiation oil recovery method is a relatively new method and has been of great interest in the recent years. Crude oil is typically co-mingled with suspended solids and water. To increase oil recovery, it is necessary to remove these components. The separation of oil from water and solids using gravitational settling methods is typically incomplete. Oil-in-water and oil-water-solid emulsions can be demulsified and separated into their individual layers by microwave radiation. The data also show that microwave separation is faster than gravity separation and can be faster than conventional heating at many conditions. After separation of emulsion into water and oil layers, water can be discharged and oil is collected. High-frequency microwave recycling process can recover oil and gases from oil shale, residual oil, drill cuttings, tar sands oil, contaminated dredge/sediments, tires and plastics with significantly greater yields and lower costs than are available utilizing existing known technologies. This process is environmentally friendly, fuel-generating recycler to reduce waste, cut emissions, and save energy. This paper presents a critical review of Microwave radiation method for oil recovery.

Fractured carbonate reservoirs contain a fraction of the world supply of oil and capillary imbibition is one of the dominant recovery mechanisms in these reservoirs. This mechanism can be affected by several parameters. To investigate capillary imbibition phenomena, we did several laboratory tests in various conditions on core samples from this fractured carbonate reservoir. In these laboratory tests, effects of parameters such as temperature, oil density, core porosity and permeability have been investigated. The results of this research work showed that rock and fluid properties can affect capillary imbibition phenomena in this type of reservoirs. On the other hand, we found that temperature has an important effect on this phenomenon, so, if we increase reservoir temperature by thermal methods, the oil recovery by capillary imbibition mechanism from this reservoir will be increased.

A problem of complex mineral resources development is urgent and priority, it is aimed at the realization of the processes of their ecologically safe development, one of its components is revealing the influence of the forms of element compounds in raw materials and in the processing products. In view of depletion of the strategic reserves of traditional metal, unconventional sources of minerals are beginning to play a leading role. Carbonaceous overburden rocks carry a heightened metallogenic potential. The possibility of extraction of valuable metals from graphitic shales, natural bitumens and overburden rocks of oil fields is considered. The results of mineralogical and technological researches of samples are presented. The analysis of sample has shown an increased content of valuable microelements in some objects. All samples contain carbon of varying degrees of metamorphism. The fact of simultaneous concentration of carbonaceous rocks by several microelements is known, the combination of them under another conditions is considerably different from chemical properties. Depending on the type of raw material, research is carried out in three directions: stadial diagnostic sorption leaching, flotation concentration, magnetic concentration and extraction. The research of the scattered carbonaceous substance from the objects of research suggests that the asphaltene fraction of bitumenoids are concentrators of metals. Research has shown the prospects of inclusion of unconventional carbonaceous raw materials for the extraction of valuable metals. (Research is executed by a grant from the Russian Science Foundation, project ¹ 15-17-00017).

With the growing concern of the world community with the environment, this work was carried out from the identification of an environmental problem, the high concentration of greenhouse gases. After identifying some possible solutions to this problem an alternative would be use them as an energy source in the process of reduction of iron ore in blast furnaces, with a feasible solution for carbon sequestration. This project aimed to use elephant grass (Pennisetum purpureum) and coal in the pulverized injection into tuyeres of the blast furnace in the steel plant. The elephant grass is a renewable source and through photosynthesis captures carbon dioxide from the atmosphere, reducing the pollution caused by the blast furnace. To simulate the possibility of injecting the materials studied, a physical modeling is used, which has been developed for this purpose. Other techniques are used to characterize the materials as size classification, combustion, calorimetry, gas analysis, microscopy, surface area, immediate and elemental chemical analysis. So, in theory, this research attempts to show that elephant grass through its injection into blast furnaces proved to be technically feasible, and it can be a way to reduce costs due to the partial replacement of fuel inputs already used and reduction of greenhouse gases.

The main parameter for determination of the possibilities to enhance oil recovery by gas injection into a specific oil field is the measurement of Minimum Miscibility Pressure (MMP). Accurate determination of this parameter is critical for an adequate design of injection equipments project investment prospect. This pressure is the lowest pressure for which a gas can obtain miscibility through a multi-contact process with a given oil reservoir at the reservoir temperature. The oil formation to which the process is applied must be operated at or above the MMP. Before field trial, this parameter is to be determined at the laboratory which traditionally is done by the help of a slim tube or a raising bubble experiments. However, because such experiments are very expensive (time-consuming), the question we want to answer in this article is as follows: Is this still another method to measure the MMP? However, in order to investigate the MMP, we suggest another method by using compositional and empirical models. For this purpose, we used some of the available experimental data from an oil reservoir with different injection gases to obtain a new MMP correlation that is suitable to be applied to this oil reservoir. We can use this obtained formula to determine minimum miscibility pressure of this oil reservoir with more accuracy.

It is difficult to use the static modeling methods to describe pumping machine mining process because of multi-variable nonlinear and time-varying characteristics. This paper proposes a new modeling approach based on Iterated Unscented Kalman Filter Neural Networks. Firstly the algorithm uses the input data to predict state variables and the covariance matrix. Secondly using the previous estimate data to resample sigma points and do unscented transforming in order to obtain the latest sampling points. Lastly, the machine mining process model with a good precision is obtained by updating state. After doing an experiment on actual production data of a certain oilfield, the results show that the proposed method in this paper has a higher modeling precision and the stronger generalization ability and stronger real-time tracking ability than UKFNN modeling method, proposed approach is an approach choice for pumping machine mining process.

Gas reservoirs can be classified into dry gas reservoirs, wet gas reservoirs and Gas condensate reservoirs. In gas condensate reservoirs, the reservoir temperature lies between the critical temperature and the cricondentherm. The gas will drop out liquid by retrograde condensation in the reservoir when the pressure falls below the dew point. This heavy part of the gas has found many application in industry and also in daily life and by remaining in reservoir not only this valuable liquid is lost but also its accumulation will result in forming a condensate bank near the well bore region which makes a considerable reduction in well productivity. This highlights the need to find an economical way to increase the condensate recovery from these reservoirs. Wells in gas condensate reservoirs usually exhibit complex behaviors due to condensate deposition as the bottom hole pressure drops below the dew point. Formation of this liquid saturation results in reduced gas relative permeability around the well bore and a loss of gas productivity. One of the several ways of minimizing the pressure drop in order to reduce liquid drop-out is hydraulic fracturing before or after the development of the condensate bank. The pressure transients are often used as a reliable evaluation of stimulation performance for field development planning. It has been shown that condensate deposits effects can be identified and quantified by well test analysis dealing with a well test composite behavior; which, in the presence of hydraulic fractures becomes much more complex. But the various impacting factors of stimulation; such as fracture length, conductivity, orientation, etc. can also be observed and defined in these analyses. In this paper, modeling and interpretation of pressure transient responses of multiple hydraulic fractured horizontal wells using a numerical reservoir model have been investigated.

The performance of Naturally Fractured Reservoirs (NFRs) is controlled by its properties such as fracture properties. In handling naturally fractured reservoirs, we need to have a comprehensive understanding of the properties and the performance characteristics of such system. Characterizing the naturally fractured reservoirs is then a paramount important in optimizing the recovery. Reservoir characterization of naturally fractured reservoirs is different from conventional reservoirs. Not only the intrinsic properties of fractures and matrix have to be characterized, but the interaction between matrix and fractures must also be understood accurately. This paper summarizes the methods used for characterization of simplified models of naturally fractured reservoirs using total reservoir response obtained from well testing.

Water injection is one of the most common oil recovery methods, and indeed, thousands of successful water injection is operated in many oil fields. This is a proven technology, which is reliable, low-risk, and economically successful even at low recovery levels. However, optimizing its performance and extending its application specifically to sandstone oil reservoirs is an important research area, which has received less attention. Studies during these years have proven that enhanced oil recovery in sandstone reservoirs can be obtained by water injection, where the injected water has a composition different from the formation water. This “smart water” is simply made by modifying the ion composition of the water and results in improved wetting properties of the reservoir causing an optimized oil recovery during production. The overall goal by injecting smart water into a porous sandstone reservoir is to displace remaining oil, increase the oil recovery, which at the end will provide more money for the oil companies and improving the countries welfare. It has been shown that the brine, crude oil and rock all play an important role in the oil recovery process. However, these interactions are complex and not easy to understand. Several mechanisms, both physical and chemical, behind the smart water EOR process have been proposed the last decade, but none of them has so far been generally accepted as the main one responsible for the observed salinity effect.
One promising trend is low salinity water injection. The impact of brine salinity on oil recovery has been an area of research in recent years. Evidence from laboratory studies, supported by some field, has distinctly shown that injecting low-salinity water has a significant impact on oil recovery, although the potential for sandstone reservoirs has not been thoroughly investigated. Recent lab and field work has illustrated that low salinity water injection can significantly improve oil recovery; while many recovery mechanisms are proposed, many questions and uncertainties remain. In this paper, we will focus on understanding physics of smart water which will improve the ability to optimize the injected water in sandstone reservoirs in the way of improving oil recovery. The “smart water” injection strategy is based on laboratory experimental observations that variation of the injected water salinity may result in large additional recovery. The idea is to inject chemistry-optimized water in terms of salinity and ionic composition into the reservoir instead of any available water that may currently be injected or planned to be injected. This process, if successfully applied, can significantly increase recovery efficiency, reserves, and production for the majority of sandstone oil reservoirs and maybe for many other oil reservoirs. Here, we will focus on sandstone oil reservoirs. Our main objectives of this to test and optimize the new process: "Smart water injection by altering the injected water salinity" for sandstone oil reservoirs aiming at enhancing oil recovery from these reservoirs and define the recovery mechanisms.

Water injection is used in the petroleum industry as a means to retain the reservoir pressure and improve oil production. Water injects into the reservoir via one or more than one injection well. The location of injection well/wells in the oil field is very important. Selecting the location of such wells has always been a question among researchers. It must be allocated such that to be able to enhance oil recovery as much as possible. Using traditional methods to optimize such well locations is infeasible due to the complexity of reservoir equations. By depleting the underground reserves, oil companies are inclined to the preservative production of oil and gas. In this paper, a case study has been studied and finding an optimal well location is investigated in order to increase recovery factor. In this case study, a non-uniform (irregular size grids) sector of an oil reservoir with two-dimensional two-phase (oil and gas) flow regime has been considered. In this reservoir, there is a strong aquifer which maintains border pressures at a constant amount. In simulation part of this study, we use IMPES (Implicit Pressure, Explicit Saturation) method to solve equations and to obtain grid pressures and water saturation during time steps. We use MATLAB mathematical package for simulation and programming. Our main purpose in this study is to find the best location for a water injection well on this oil field to increase oil production as much as possible.

Several formulas have been presented to calculate permeability in hydrocarbon sandstone reservoirs by various researchers. This fact that the volume of shale in a sandstone reservoir is the main controlling parameter is the base of this paper. So, the other parameters have been supposed to be fixed such that effect of shale volume can be investigated more easily. In this paper, the relationships between porosity and permeability and between shale volume and permeability have been used to derive a formula for permeability calculation in sandstone reservoirs.

This paper deals with a study of new topology using a polynomial controller RST.The topology copies the IP structure.The new controller is applied on powers control of a doubly fed induction generator (DFIG) used in a chain of wind power conversion.Simulation results show that the new proposal leads to good performances as test tracking, disturbance rejection and robustness in respect of parameters variation like rotoric resistance.

Predicting the flow of fractured reservoir fluids is a key factor in making the right field development decision, such as the placement of future wells. In any field, accurate flow models are difficult to achieve simply because of the scarcity of data from existing wells and outcrops. In fractured reservoirs, the problems are compounded by the highly heterogeneous nature of the rocks. So, predicting fluid flow behavior in naturally fractured reservoirs is a challenging area in petroleum engineering. Successful extraction of hydrocarbons from many remaining domestic exploration and development targets depends on the creation of new approaches to predicting natural fracture attributes. So, we must develop new understanding and new technology for prediction of fracture-pattern attributes related to subsurface fluid flow. In recent years interest has increased considerably on flow and transport in low-permeability fractured rock. Two classes of models used to describe flow and transport phenomena in fractured reservoirs are discrete and continuum (i.e. dual porosity) models. The discrete model is appealing from a modeling point of view, but the huge computational demand and burden in porting the fractures into the computational grid are its shortcomings. On the other hand, the diagonal representation of permeability, which is customarily used in a dual porosity model, is valid only for the cases where fractures are parallel to one of the principal axes. This assumption cannot adequately describe flow characteristics where there is variation in fracture spacing, length, and orientation.

In formations where the sand is porous, permeable and well cemented together, large volumes of hydrocarbons which can flow easily through the sand and into production wells are produced through perforations into the well. These produced fluids may carry entrained therein sand, particularly when the subsurface formation is an unconsolidated formation. Produced sand is undesirable for many reasons. When it reaches the surface, sand can damage equipment such as valves, pipelines, pumps and separators and must be removed from the produced fluids at the surface. Further, the produced sand may partially or completely clog the well, substantially lead to poor performance in wells and, ultimately, inhibiting production, thereby making necessary an expensive work-over. In addition, the sand flowing from the subsurface formation may leave therein a cavity which may result in caving of the formation and collapse of the casing. Sand production in oil and gas wells can occur if the fluid flow exceeds a certain threshold governed by factors such as consistency of the reservoir rock, stress state and the type of completion used around the well. The amount of solids can be less than a few grams per cubic meter of reservoir fluid, posing only minor problems, or a substantial amount over a short period of time, resulting in erosion and in some cases filling and blocking of the wellbore. Although major improvements have been achieved in the past decade, sanding tools are still unable to predict the sand mass and the rate of sanding for all field problems in a reliable form. This paper provides a review of selected approaches and methods that have been developed for sanding prediction. Most of these methods are based on the continuum assumption, while a few have recently been developed based on discrete element model. Some methods are only capable of assessing the conditions that lead to the onset of sanding, while others are capable of making volumetric predictions. Some methods use analytical formulae, particularly those for estimating the onset of sanding while others use numerical methods, particularly in calculating sanding rate.

Among existence methods for produced water removal from oil reservoirs, water re – injection into underground layers of reservoir has been considered as a suitable method. But solid particles and other pollutants in this water will damage reservoir formations. Scale deposition is one of the most serious oil field problems that inflict water injection systems primarily when two incompatible waters are involved. Formation damage in this process is similar to cross-flow filtration. In this paper, external cake formation on well bore has been modeled in unsteady state conditions. For this purpose, first, the forces will be analyzed; then, fluid force and mass balances in unsteady state condition will be written. Finally, cake thickness, invasion and well fluid velocity profiles in unsteady state condition will be obtained.

Sand production is a serious problem in oil and gas reservoirs worldwide. It can drastically affect production rates. The adoption of a sand management strategy is crucial for prolonging economic reservoir development for sand producing reservoirs. Significant gains in production (acceleration) and reserves (IOR) can be resulted from the pursuance of sand management in these fields. Such a strategy requires that the sand production is managed in a safe and controlled manner where the negative consequences of sand production are manageable and predictable. Sand management has been identified as one of the key issues in field development in most of the world’s oil and gas fields. Sand management is not just about the selection of sand control systems - it is about maximizing and maintaining production while managing sand at acceptable rates. Successful sand management can only be achieved with a fully integrated, multi-disciplinary team. Facilities sand management is tasked with the goal of ensuring sustained hydrocarbon production when particulate solids (i.e. sand) are present in well fluids, while minimizing the impact of these produced solids on surface equipment. Particle size and the total concentration of formation sand determines their net effect on production and the resulting operability of surface facilities. Conventional sand management control focuses on sand exclusion from the wellbore, either by production limits or completion design. Completions may adversely affect inflow due to skin buildup and both controls impede maximum hydrocarbon production. Alternatively, co-production of fluids and solids, with subsequent sand handling at surface facilities, is an inclusion paradigm that allows sustained hydrocarbon production. Produced solids are removed at the wellhead upstream of the choke using the fit-for-purpose equipment. This methodology allows for increased or recovered hydrocarbon production, while their removal upstream of the choke protects facilities operations.

Sand production is a major issue during oil and gas production from unconsolidated reservoirs. In predicting the onset of sand production, it is important to accurately determine the sand production mechanisms and the contributing parameters. The aim of this study was to determine sand production mechanism in an oil reservoir, identify the major contributing parameters and evaluate their effects on sanding. Sand failure mechanisms and contributing parameters were identified. The results showed that cohesive stress is the predominant sand failure mechanism. Sand strength, grains movement, shear and tensile strengths impact sand production too.

Underbalanced drilling (UBD) is defined as the practice of drilling a well with the wellbore fluid gradient less than the natural formation gradient. It differs from conventional drilling in that the bottom holes circulating pressure is lower than the formation pressure, thereby permitting the well to flow while drilling proceeds. Underbalanced drilling technology is a valuable method for minimizing formation invasion related problems. Because the majority of hydrocarbons today are found in existing fields with depleting pressures, or in complex and low-quality reservoirs, the economical use of UBD becomes more and more popular. This technology can save the industry millions of dollars by increasing the amount of recoverable oil within a shorter time frame. Historically, most underbalanced drilling (UBD) projects were undertaken to eliminate drilling problems and cost. However, recently, the reduction of formation damage has become the main focus for underbalanced operations. This has the greatest potential indirectly increasing the profit to the operating company. Potential benefits include increasing of production rate, the ultimate recovery, and enabling accelerated production. Underbalanced technology, while still on a sharp growth curve, is finally becoming accepted as a normal method for handling the drilling and completion of wells.
Use of supercritical carbon dioxide (CO2) in underbalanced drilling operation has been investigated in this paper. The use of carbon dioxide in an underbalanced drilling operation eliminates some of the operational difficulties that arise with gaseous drilling fluids, such as generating enough torque to run a down holes motor. The unique properties of CO2, both inside the drill pipe and in the annulus are shown in terms of optimizing the drilling operation by achieving a low bottom hole pressure window. Typically CO2 becomes supercritical inside the drill pipe at this high density; it will generate enough torque to run a down holes motor. As the fluid exits the drill bit it will vaporize and become a gas, hence achieving the required low density that may be required for underbalanced drilling. Both single phase CO2 and a mixture of CO2 and water have been studied to show the effect of produced water on corrosion rates.

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