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Collaborating Authors
Precipitates (paraffin, asphaltenes, etc.)
Abstract Organic deposition predominantly in the near well bore and in production tubing can create serious oilfield problems such as flow restrictions, near wellbore damage, efficiency of crude processing units and etc. As the reservoir depleted over the time, the solid deposition can lead to a steep decline in productivity of wells. The deposition of organic solids is one of many flow assurance problems faced by operators in Malaysia. It has been observed that, after years of production, many fields in Malaysia are suffering from organic solid deposition problem. This phenomenon is predominantly caused by changes in temperature, pressure and composition/morphology of the crude oil over time. To perform organic deposit removal treatment and prevention in the well, the nature of the solid should be characterized. If the deposit sample is organic mainly, it is important to quantify the various organic fractions of the solid sample collected from the production facilities. This paper explains how SARA analysis was modified to detect not only Macro-crystalline waxes (Saturates), asphaltene, aromatics and resins but also micro-crystalline wax and naphthenates. The content of each of above component will affect the method of treatment and the chemical formulation to treat the well. By knowing the composition of the solid sample along with Crudeโs Colloidal instability index (CII), Pour point and Wax Appearance Temperature (WAT), a customized chemical formulation can be designed. Lab studies were performed on solid samples collected from several wells to detect the flow assurance related issues prior to design of chemical formulation. With the analysis of the production data, history matching, and etc, a customized chemical formulation was developed to treat the wells. The proposed chemical formulation consists of 2 specially designed pills which would be simultaneously injected to the wellbore, which generates heat and ester once comingles. The heat melts the deposits while the ester disperses the melted solid. The initial studies of the treatment showed promising results; moreover the field implementation was very successful and proven significant increase in production rate. This novel system that combines both thermal and physical energy, evidenced to work effectively for wide range of organic compositions. Implementation of this system made it possible to restart the production from those wells which were idle due to extensive organic deposits. This technique was also often used to rejuvenate the old wells with low production rate. This paper discusses the diagnostic process and successful implementation of the proposed treatment in several oil wells in Malaysia.
- North America > United States (1.00)
- Asia > Malaysia (0.89)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.73)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- (2 more...)
Abstract Wax and asphaltenes are well known to cause problems through adhesion and build-up on pipeline walls, restricting flow. Deployment of chemical inhibitors is commonly used in subsea pipelines. Measurement techniques for both asphaltenes and waxes commonly show widespread data scatter. Selection of inhibitor chemicals for both wax and asphaltenes are commonly based upon simple tests conducted on stabilised oil samples. This commonly leads to higher dose rates being used than actually required in the pipeline to successfully reduce or eliminate surface build-up. We have developed a small volume testing facility for measuring wax and asphaltene phase equilibria and optimising inhibitor deployment. The developed device is based on Quartz Crystal Microbalance (QCM) Technology. The QCM is locally cooled to create a temperature gradient between bulk fluid and the surface of the QCM, simulating wall cooling effect. Different temperature gradients could be simulated. The developed device needs 35 ml of fluid and can work at high pressure conditions, simulating effect of pressure and dissolved gas on wax phase behaviour and adhesion tendencies. For wax evaluation, the device can closely simulate a typical "Cold Finger" test with many extra benefits, including; small size of the sample, being non-destructive, real time deposition rate, using live samples (as well as dead/stabilised samples). In this communication we present some of the results generated using QCM Technology including Wax Appearance Temperatures (WAT) and Wax Disappearance Temperatures (WDT), wax inhibitor screening and results on asphaltene onset determination and inhibitor assessment. Results using the first prototype comparing with "Cold Finger" wax inhibitor screening and showing the effects of temperature gradient and pressure on wax build up for a live oil are presented. The results show that the device and technique proposed in this communication can provide a robust, reliable method for evaluating solid formation and deposition risks using very small sample volumes.
- Asia (0.69)
- North America > United States > Texas (0.28)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Precipitates (paraffin, asphaltenes, etc.) (1.00)
Abstract The industry drive to develop marginal fields, heavy oil, or increased oil-recovery options from new or existing fields requires that the design of system components be examined and questioned. Extended-reach (cold water) flowlines that transport unprocessed fluids from the wellbore through to a receiving or processing facility require effective insulation systems or an active heating system to assure the integrity of the fluids in the line. Additionally, to meet flow-assurance requirements, production chemistry is used at the inlet of a flowline to prevent the formation of hydrates and to manage paraffin wax or scale formation. The production chemicals are usually injected through chemical-transportation facilities in an electrical/hydraulic-control umbilical that is laid parallel to the flowline. Flowline active-heating systems and high-performance insulation systems add significantly to the capital cost of a project; additionally, the design and fabrication of control umbilicals that include multiple chemical-injection conduits increase the capital required to develop a field. This paper presents a new concept in flowline active-heating and chemical-injection systems that will reduce the capital cost of flowline and umbilical infrastructure while enabling significant flexibility in the application of production chemistry. The system challenges of existing flowline design, umbilical design, and the philosophies of field operational maintenance/pigging are reviewed.
- Geology > Mineral > Sulfate (0.48)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.34)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Piping design and simulation (1.00)
- (3 more...)
ABSTRACT During production of crude oil, temperature and pressure of the produced fluid decreases along its production pathway. The reduction in pressure and temperature disturbs the equilibrium of the composition of the oil particularly the heavier components leading to their separation, precipitation and deposition at in-and-around well bore (skin effect) and production tubing. Such a deposition can choke the flow passage from reservoir to well bore and reduce the production of oil appreciably (Diagram 1). A unique two pack chemical system had been developed as an effective tool for:Removal of organic deposits, such as in-and around well bore (skin) and production tubing Enhancement of production rate The two pack chemical system when injected into the well bore through production tubing, reacts to produce in-situ heat with a reaction product. The heat generated in the system can dislodge and melt the deposits and the reaction product formed acts as dispersant and an effective surfactant. The paper presents the results on two wells which were pilot implemented in Malaysian Offshore field, Temana (TE). Among the two treated wells, one well was a closed-in well while the other was gas lift producing well. Both wells had shown appreciable decrease in skin factor, reduction in water production and sustained an additional average incremental production of 190 to 320 bpd for the past one year. Pay back period of the treatment cost was between 11 to 19 days. The wells are still producing after one year of treatment. The two pack chemicals system and related chemicals, and their reaction product are compatible with crude oil, rock formation, tubular steels and oil field rubber parts. INTRODUCTION The rate of crude oil production in a well varies directly with reservoir pressure and inversely with the resistance experienced to its flow from reservoir to storage tank. During the production process, the temperature and pressure along the production path of the producing wells decrease with the change in oil composition, increase in viscosity and change in chemical equilibrium with respect to crude oil and water produced. The change in equilibrium can lead to separation, precipitation and deposition of heavy organic components of the crude oil and inorganic scales from the formation water. While nature and extent of the organic solids depend on the composition of crude oil, the nature and extent of the inorganic solids depend on the composition of formation water. As the change in temperature and pressure is more apparent at in-and-around the well bore (Diagram 2); maximum deposits of heaviest solids can be expected at this location. Such deposits can choke the formation in-and-around well bore reducing its effective permeability appreciably and reduce the rate of crude oil production. Not only solids deposit at in-and-around well bore, but production tubing and flow lines as well (Diagram 3). The presence of fines (sand, silt, clay and scales) at in-and-around well bore and production tubing can further deteriorate the flow passage chocking thereby further reduce the crude production. There are two types of organic deposits. One is composed primarily of paraffin (commonly refers as wax) and the other of asphaltene.
- North America > United States (0.28)
- Asia > Malaysia > Sarawak > South China Sea (0.24)
Abstract Contact angles are used to measure the wetting behavior of two immiscible fluids on a solid surface. Fluids are considered wettings if their contact angles with surface are less than 90ยฐ, and they are considered non-wetting, if their contact angles are greater than 90ยฐ. Because of its influence on other petrophysical properties of reservoir rocks, such as relative permeability, capillary pressure, and the residual oil saturation after a flood, wettability and its direct measure, the contact angle, play a significant role in affecting the recovery from both primary and improved recovery processes. In this work, contact angle alteration occurring in microbial enhanced oil recovery processes (MEOR) are quantififed and described, along with a study of the factors that would enhance such contact angle alteration. An experimental method for the measurement of contact angles has been developed in which the contact angle is measured as a function of time. Measurements of contact angle and interfacial tension for four different types of UAE crude oil and four different mineralogical rock composition over a range of microbial concentration, salinity, and temperature are reported. Results showed that contact angles for the studied systems increased with temperature, crude oil sulfur concentration and microbial concentration up to a certain concentration, beyond which the bacteria concentration exhibited no effect on the contact angle. Crude oils containing low asphaltene concentration produced a stable contact angle and oils containing high asphaltene concentration produced surfaces with unstable wettability. The mineralogical composition of limestone rocks had no effect on the contact angle of microbial-oil system. Introduction The wettability of porous media has been shown by a number of investigators to affect rock-fluid properties such as the capillary pressure and the relative permeabilities, and thus plays a big factor in determining the recoveries resulting from water floods. Contact angles are commonly used to measure the wetting property of a solid surface with respect to two immiscible fluids. Young's equation provides a definition of contact angle in terms of a surface energy that interrelates the interfacial tensions of the three phases.sos=s ws+sow cos ? ow (1) The contact angle is a thermodynamic property and provides a definition of wettability. As the two main fluids in the reservoir are crude oil and brine, reservoirs are thus classified as either water-wet or oil-wet. Sandstone reservoirs are typically water-wet, while carbonate reservoirs, such as reservoirs in the U.A.E., are oil-wet. Water flood performance in water-wet reservoirs is much more efficient than in oil-wet reservoirs. Zisman has summarized a large body of air /liquid contact angle data measured on polymeric solids and on adsorbed organic monolayers laid down by the Langmuir-Blodgett technique on metal substrates. Treiber et al. measured the water advancing contact angle for 55 reservoirs with synthetic formation brine and observed a wide distribution of advancing contact angle.
- North America > United States (1.00)
- Asia > Middle East > UAE (0.46)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.72)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.54)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Microbial methods (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Precipitates (paraffin, asphaltenes, etc.) (1.00)
Abstract One of the most severe problems at any oil fields producing paraffinic oils is wax/paraffin deposition. The microbial treatment that based on the activity of the naturally occurring, selectively isolated bacteria is a proved effective alternative method to the conventional methods to prevent and remove wax deposition. This article discusses the screening and evaluation of bacterial strains on the effect of biodegradation on the heavy paraffinic hydrocarbon components (C1), especially normal alkanes. The experimental results of cloud point temperature measurements show that as the apparent molecular weight of crude oil (solution) decreases, its cloud point temperature also decreases. So that, wax precipitation will be delayed. Therefore, microbial biodegradation of heavy paraffinic hydrocarbon components, especially normal alkanes, will be one of the most effective methods to prevent wax precipitation and deposition. Three bacteria strains and four different consortia of them were used through the experiments. The three strains were Bacillus subtillis, Bacillus licheniformis, and Pseudomonas aeruginosa. Gas chromatography, infrared spectroscopy (IR), and NMR analysis were performed on the samples before and after microbial treatments. Also, the physical properties of samples were measured before and after treatments. Based on the physical characteristics of samples and on the results of their special analysis, the Pseudomonas aeruginosa strain was highly effective in the degradation of normal alkanes between C16-C25 and Bacillus licheniformis was highly effective in the degradation of cyclo- and iso- alkanes between C20-C30. In contrast, Bacillus subtillis had no or less effect on the degradation of heavy paraffinic hydrocarbons. Where as, through out the literature, Bacillus subtillis was introduced as one of the effective microorganisms in the biodegradation of heavy paraffinic hydrocarbon components. Introduction Paraffin may be deposited throughout the oil producing flow lines from the inside of oil reservoirs to stock tanks of refinery. That is due on one hand to system temperature lowered below the crude cloud point temperature and on the other hand, to the composition change of the crude, in which the lighter components (C1-C15) have been evaporated or stripped from the oil. The later case leads to the less solubility of paraffins. Since 1900, several varieties of methods have been proposed and applied to overcome the problem. The injection of chemicals such as solvents and dispersants among the conventional methods, is very successful for the control of paraffin precipitation and deposition. However, the chemical treatments proved to be costly and highly toxic. During the last decade, microbial remediation has been selected as an alternative method to the conventional methods. Although the interactions between microorganisms and crude oil especially biodegradation mechanism, have been studied over the past 40 years, but its mechanisms and by-products have not been fully identified yet. The main metabolisms of microbial treatment may be classified as biodegradation and production of chemicals like organic (fatty) acid, biosurfactants, alcohol, acetones, ethers, and gases. Experimental results show that the cloud point temperature, i.e. the precipitation or crystallization temperature of paraffin is the very important and impressive factor in wax precipitation. It might be taken as the basic parameter of the problem. On the other hand, it was concluded from our experimental results that the cloud point temperature might be a function of solute and solvent weight fractions, and their molecular weights. Application of biodegradation will reduce the paraffin (solute) weight fraction and conversely increases the solvent weight fraction, i.e. the molecular weight of paraffin will be decreased and molecular weight of solvent will be increased. Consequently, the cloud point temperature of crude oil will be lowered by biodegradation mechanisms, which reduces the long chain alkanes into short chains.
- North America > United States (0.46)
- Asia > Middle East (0.29)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Reservoir Description and Dynamics (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Precipitates (paraffin, asphaltenes, etc.) (1.00)
Abstract Ras Budran (R/B) field is located 5Kms. offshore at the eastern coast of the Gulf of Suez and consists of a massive Nubian Sandstone Reservoir compartmentalized by partially major faults. The field is undersaturated and production is maintained by gas lifting while the pressure is supported by a combined water flood and limited aquifer drive. The R/B produced crude oil has an intermediate base with asphaltene content ranging from 10โ15% wt and an average API Gravity 25ยฐ. With the increase in water production and injected seawater breakthrough a very viscous tough emulsion was formed in some wells, causing production problems. Also, due to scale deposition, calcium carbonate and sulphate, the hydrochloric acid and other scale dissolvers were applied to clean the tubing and the formation. Some of these additives have an adverse effect on the emulsion viscosity and cause asphaltene deposition. The paper presents the study carried out to identify the problem and find a solution for it. The study includes:The rheological properties of the emulsion at different downhole conditions; shear rates, temperatures and water contents at different salinities. The effect of the different chemicals used for scale removal and inhibition on the asphaltene deposition and the produced crude oil emulsion viscosity. The effect of the flow improver products; demulsifier, Asphaltene dispersant, viscosity and drag reducers...etc. on increasing the fluidity and reducing the drop in pressure of the produced crude oil emulsion. The study results showed that the hydrochloric acid causes asphaltene deposition and tough emulsion formation. Also the increase in the water content form a very tough/viscous emulsion at a certain percentage, which is defined as the inversion point, below and above this percentage the emulsion viscosity is reasonable. The injection of the flow improver chemicals through the gas lift valves could reduce the emulsion viscosity. Introduction Suez Oil Co., (SUCO) is one of the biggest oil producing companies in Egypt. Our field of concern Ras Budran (R/B) is operated by SUCO, located 5 Kms offshore at the eastern coast of the Gulf of Suez. The current production of R/B oil field is about 20,000-bbls/day crude oil. Ras Budran crude is asphaltic base crude oil with asphaltene contents ranged from 10โ15% by weight and average API gravity of 25ยฐ. The company is currently applying water injection strategy to increase the productivity of the wells. Due to the water injection and the nature of R/B crude oil, very viscous tough water-in-oil emulsion is formed in some of the producing wells and causes a significant decrease in the wells productivities. This paper summarized the work done to study the rheological properties of R/B crude oil emulsions formed downhole. The rheological properties were measured at different water/oil ratios, shear rates and at two temperatures. Emulsions inversion points were determined. Effects of the chemicals used for scale removal/inhibition and flow improvers on the emulsions behaviors were also studied. Background Formation of Emulsions An emulsion is a mixture of two mutually immiscible liquids, one of which is dispersed as droplets in the other, and is stabilized by an emulsifying agent. The dispersed droplets are known as the internal phase. The liquid surrounding the dispersed droplets is the external or continous phase. In the oil field, oil and water are encountered as the two phases. They generally form water-in-oil emulsion, although occasionally the reverse or oil-in-water emulsion is formed. The emulsion produced is thermodynamically unstable and this is why pure water and pure oil will never form emulsion no matter how much agitation is applied.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.54)
- Geology > Mineral (0.48)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Downhole chemical treatments and fluid compatibility (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Precipitates (paraffin, asphaltenes, etc.) (1.00)
Abstract The continuous pursuit to discover new hydrocarbon reserves is driving oil and gas exploration companies to explore in more challenging environments, such as in deep water. One of the major challenges in these environments is to understand the characteristics of hydrocarbon solids deposition and its potential for production disruption. Asphaltenes are one of the hydrocarbon solid materials that have the potential to form, flocculate, and deposit in the production circuits. This process can come about as a result of changes in pressure, temperature, and/or composition. In this paper, we present a systematic approach to characterize asphaltene materials using state-of-the-art technologies. In summary, a fixed-wavelength near-infrared light-scattering technique (NIR) is used to prescreen the thermodynamic onset of asphaltene flocculation. Subsequently, a variablewavelength spectral analysis system (SAS) is used to estimate the asphaltene particle size and the growth kinetics. Finally, a high-pressure microscopy (HPM) technique is used to better understand the morphological behavior of the asphaltene materials. These laboratory techniques can greatly enhance the understanding of asphaltene flocculation and the risk of potential deposition at the beginning of field development. As a result, operators may have the option to proactively prevent deposition or design remediation methods during the planning phase of the deepwater development that will reduce the risk of flow disruption. Introduction Development activities in the deepwater face significant challenges. Of particular concern are the effects of produced fluid hydrocarbon solids (i.e., asphaltene, wax, and hydrates) and their potential to disrupt production throughh deposition in the production tubulars. There is a systematic approach to characterize reservoir fluid for all three flow assurance issues. Of the hydrocarbon solids, the thermodynamics and kinetic aspects of wax and hydrates are reasonably well understood, and results of various studies have been published in the literature. On the other hand, the understandings of the thermodynamic and kinetic aspects of asphaltenes formation and deposition are not yet well developed. Limited amounts of experimental data on the thermodynamic behavior of asphaltenes have been reported in the literature.. Various laboratory techniques such as gravimetric, filtration, fluorescence, spectroscopy, conduction, acoustic resonance, and light scattering have been used in determining the onset of thermodynamic instability resulting in asphaltene flocculation. A detailed description of these various methodologies has been presented in Reference 8. Only recently, the kinetic aspect of asphaltene flocculation has been reported by Nighswander et al. In this work, a systematic approach is presented for understanding the thermodynamic and kinetic aspects of asphaltenes using various state-of-the-art laboratory techniques. The identification of thermodynamic conditions at which asphaltenes start to form and the rate at which they grow are the first steps forward in evaluating economic feasibility. If asphaltenes are anticipated, the next step is an understanding of the effect these asphaltenes will have on the hydrodynamic conditions during production. Knowledge of asphaltenes will allow the production engineer to devise a suitable flow assurance strategy and assess the economics of a potential field development with less uncertainty.
- Asia (0.93)
- North America > United States > Texas (0.46)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.47)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Precipitates (paraffin, asphaltenes, etc.) (1.00)
Abstract In this project, steam was tested to stimulate damaged limestone cores. Several dynamic experiments were conducted to determine the effect of asphaltene on the permeability of limestone cores. Plugging effects due to asphaltene deposition were evaluated through comparison with reference permeability measured prior to and after oil flow. Damaged cores were then subjected to steam soak process. The permeability of the cores was measured after each treatment. Core impairment resulting from in-situ asphaltene deposition, was found to cause a 56 to 89% loss of initial oil permeability depending on rock permeability and injection rate. Core stimulation resulting from steam soak treatment, was found to cause 24 to 230% improvement on the damaged core permeability depending on rock permeability. On average, 95% improvement in damged core permeability was obtained. Introduction Many field cases and laboratory studies have reported precipitation and deposition of asphaltenes during the recovery of oil. Asphaltenes deposition generally appeared in the field first in surface facilities, especially in separators, during the oil final depressurization step. Another critical point along the production chain is within tubing in which precipitate form at depths corresponding to the bubble point pressure of produced oil. In some field cases, the reported asphaltene deposition in reservoirs has been so severe that reduced well productivity and injectivities. Asphaltenes are generally found in all crude oils. They are defined as a solubility class of the heavy components in the crude oil that are insoluble in a non-heavy (n-alkenes) solvents such as pentane. They are complex polar macro-cyclic molecules that contain carbon, hydrogen, oxygen and sulfur Asphaltene are aromatic and occur partly dissolved and partly dispersed colloidal suspension stabilized by non-polar resins and maltenes fraction of the crude. The ratio of polar to non-polar components and the ratio of high to low molecular weight components control the solubility of asphaltenes, resins and maltenes within the crude. Crudes with high resin and maltene content are more stable. Any actions of chemical, mechanical or electrical nature will result in alteration these ratios and consequently depeptize the asphaltene micelle and cause their destabilization/flocculation. For example, crudes that have a low aromatic content have a higher degree of asphaltene instability and the addition of aromatics will increase the crude stability for asphaltene, thereby reducing the likelihood of asphaltene precipitation. Precipitation and deposition can also be caused by variation in pressure and temperature. Temperature effects are important since the higher the temperature the greater the solubility of the resins in the n-alkanes and therefore the less soluble the asphaltenes in the crude. All crudes will experience some compositional changes during production from reservoir to surface pressure. The molar volumes of the fractions of the crude will change due to depressurization of the crude. The light ends, which are predominantly straight chain n-alkanes will expand relatively more than the heavier components of the crude. The increase in molar volumes of the light ends will continue up to the fluids bubble point pressure. Below the bubble point the light ends will leave the fluid as gas. This will result in a decrease in the molar volume of the light ends causing a decrease in the n-alkanes concentration. Since the solvency of asphaltenes in crude oil is dependent on the on the ratio of aromatics to n-alkanes all crudes will experience a minimum solvency just above the bubble point. Wether this will be sufficiently low to result in asphaltene precipitation will depend on the factors above i.e. the ratio of resins to asphaltenes, the crude solvency and the temperature.
- North America > United States > Texas (0.93)
- Asia > Middle East > UAE (0.68)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- South America > Brazil > Alagoas > South Atlantic Ocean > South Atlantic Ocean > Sergipe-Alagoas Basin > Camorim Field (0.99)
- South America > Brazil > Alagoas > Sergipe > South Atlantic Ocean > Sergipe-Alagoas Basin > Camorim Field (0.99)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Precipitates (paraffin, asphaltenes, etc.) (1.00)
Studying the Mechanism of Magnetic Field Influence on Paraffin Crude Oil Viscosity and Wax Deposition Reductions
Tung, Nguyen Phuong (Institute of Materials Science-Vietnam NCNS) | Van Vuong, Nguyen (Institute of Materials Science-Vietnam NCNS) | Long, Bui Quang Khanh (Institute of Materials Science-Vietnam NCNS) | Vinh, Ngo Quang (Institute of Materials Science-Vietnam NCNS) | Hung, Pham Viet (Institute of Materials Science-Vietnam NCNS) | Hue, Vu Tam (Petro Vietnam) | Hoe, Le Dinh (Vietsov Petro)
Abstract Dragon and White Tiger crude oils are two different kinds of paraffin crude oils of Vietnam. The screening studies on their fluidity changes under the influence of magnetic forces have been completed. The relationships between their viscosity changes and magnetic force strength, temperature, and duration of treatment were obtained, the optimal conditions for the viscosity reducing were found. The changes in paraffin crystallization under magnetic fields were studied using scanning electronic microscopy (SEM). The possibilities to defense and remove wax clogging and deposition obtained by magnetic treatment was also studied and proved. Base on these data, the mechanism of the influence of magnetic fields on paraffin deposition control was proposed. The data can also serve as a basic in designing and construction high effective magnetic tools to improve liquidity of high waxy crude oils in this area. Introduction Paraffin or wax deposition has been recognized as a major problem from the inception of oil industry all over world. It can occur and present a lot problems in oil production, transportation and storage. These cause the reduced crude oil pumping rate, severe start up problems after pipeline shut down and wax deposition. Paraffin deposits on the wall of down hole turbulars and other places like near entrances and exit of chokes, collars of similar restrictions in the flow path. Among existing two physical and chemical groups of methods to control this problem, wax crystal modifiers maybe the best in able to resolve, partly, these low temperature troubles by modifying the rheological properties of waxy crudes and decreasing wax deposition, resulting in a better pump ability and restability. Despite these advantages, the chemicals are expensive, environmentally hazardous, they also are very sensitive, they can work effectively only on specific crudes. There was one more method, the magnetic technology, which was based in an applied magnetic fields, can very successfully remove or inhibit crude oil gathering deposits, both organic and inorganic without affecting the crude characteristics. Despite the magnetic technology has been cited in the literature and studied since nineteenth century, while naturally occurring magnetic mineral formations were used to decrease the formation of scale in cooking and laundry applications, and now a day, a thousand of magnetic fluid conditioners (MFC) have been installed in oil wells in many places in the world , the mechanisms of its effects on deposition control, especially on crude oil wax deposition was not so far clearly studied and proved. The purpose of this study is to confirm that magnetic fields effect on liquidity of crude oils via fluid viscosity and paraffin crystallization process, and try to find out the mechanisms of these effects.
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Precipitates (paraffin, asphaltenes, etc.) (1.00)