Abstract
This paper is the result of five years experience with ESP applications and extensive search of published data. Containing information about the complex nature and behavior of asphaltene in crude oil, and evaluating the conditions under which asphaltene particles precipitate from oil. In addition, different approaches to prevention and treatment of asphaltene sludge are presented and summarized using the results obtained from several oil fields in Alberta, Canada.
Asphaltene deposition has threatened the economic recovery of oil, or increased considerably, the cost of producing it. In many cases the asphaltene problem was not foreseen, neither during the exploration nor during the development phase of the oil discovery. In the present paper, asphaltene structure, as well as its chemical and physical properties are evaluated in order to understand asphaltene behavior in oil during thermodynamic equilibrium and during flocculation and deposition. It is shown that asphaltenes can exist in oil in various states such as molecular, steric colloidal, micellar, and solid. Asphaltenes in crude oil are stabilized by the presence of resins and maltenes. There is an important relationship between asphaltene deposition and resin concentration in oil. Heavy crudes may be stable if they contain a high resin to asphaltene ratio, while light crudes may deposit asphaltene easily if there is not enough resins to stabilize the asphaltene particles. Other factors contributing to asphaltene precipitation include pressure drop, temperature change, streaming potential, miscible or CO2 flooding, acidizing of the well or mixing incompatible crudes. Besides the destabilizing factors, the regions of actual deposition are of great interest because they will probably determine the extent of damage. Asphaltene can form deposits around the wellbore region, well tubing, flowlines, separators, pumps, tanks and other production handling equipment. The most troublesome place of deposition is near the wellbore area due to the possibility of formation damage and/or temperature/pressure change due to use of ESP's. Besides using the old treatment methods (use of solvents, dispersants and inhibitors) for asphaltene deposits, new methods to prevent asphaltene deposits in downhole pumps have been developed. They include the use of Variable Speed Controllers (VSC) combined with oversized pumps, increased impeller vein heights, internal pump coatings, reduced pressure drop at the pump intake and injection capillary. However, the choice of chemicals and methods to be used depends on the well conditions. The methods used should be customized precisely to the well in order to achieve the best results.
Introduction
Since the 1930s, researchers have been trying to define and understand asphaltenes in crude oil. When asphaltenes are present in crude, they can cause severe processing problems at any point – from the formation to the refinery. Much research has been focused on the crude oils since problems such as deposition and emulsion stabilization are encountered during oil recovery and production. However, in spite of all these efforts, asphaltenes deposition still ranks as one of the costliest technical problems the Petroleum Industry faces today. Precipitation of asphaltenes in reservoirs, wells, downhole equipment, and facilities causes severe detrimental effects on the economics of oil production because of reduction in well productivity and/or clogging of the production facilities. The questions of interest in the oil industry today are “why”, “when”, and “how much” asphaltenes will flocculate out under certain conditions. Since petroleum crude generally consists of mixtures of hydrocarbons and heavy organics, it has become necessary to look at the constituents of oil as polydispersive or discrete mixtures, interacting with each other. The onset and amount of heavy organics deposition will vary depending on the hydrocarbons present in oil and the relative amounts of each family of heavy organics.
Purpose. The purpose of this paper is to present the problem of asphaltene deposition during oil recovery and production with focus on ESP application. Asphaltene structure, it's physical and chemical properties, as well as, mechanisms of flocculation and deposition will be analyzed. This paper will also include damage caused by asphaltene deposition in the ESP equipment. The applications and effectiveness of the old and new methods, of prevention and removal of heavy hydrocarbons deposits, will be presented and supported by reference to field studies from Canada.
Scope. The first section of this paper will try to define the complex nature of the asphaltene molecule, its chemical constitution and physical properties when present in oil. It will also include information about other constituents of crude, especially natural resins. The effect of oil composition on asphaltene stability as well as other destabilizing factors including chemical, mechanical means, pressure, temperature drop, and streaming potential will be evaluated in the second part of this paper. Next, this paper will concentrate on the solutions to the asphaltene deposition problems in wells with ESP completion. Use of solvents and dispersants, combined with modifications to ESP equipment, will be presented and evaluated. Case studies from Canadian oil fields will support the evaluation by providing information about the effectiveness of some of the methods. The conclusion will summarize the extent of the damage caused by asphaltene deposition in the ESP equipment, and the improvement in the methods of handling crude oil that may be subject to asphaltene deposition.
Characterization of Asphaltene and Resin
In petroleum fluids, asphaltenes and neutral resins are the most common of all aromatic fractions, which also include asphaltogenic acids, carbenes, and carboids. The chemical constitution of asphaltenes and resins is difficult to investigate due to their complex nature. Asphaltenes are constituents of the heavier, non-volatile polar fraction of crude oils. They are broadly classified as n-pentane insoluble and benzene soluble. Neutral resins are soluble in pentane and insoluble in alkalies and acids.
Molecular Structure and Composition of Asphaltene and Resin. Asphaltenes are heterocyclic geomacromolecules consisting primarily of carbon, hydrogen and minor components, such as sulfur, nitrogen and oxygen. Resins share the same building compounds as asphaltenes, but are smaller molecules and have a higher proportion of paraffinic chains attached to condensed aromatic rings [2]. In the natural state, asphaltenes often contain a significant concentration of nickel, iron, and vandium. Chemical scientists have agreed on the hypothetical empirical formula of C74H87NS2O to represent an average asphaltene structure. However, the exact molecular structure is not generally known, as it could vary from well to well. The difficulties in analyzing the structure and properties of asphaltenes are due to the fact that neutral resins are strongly adsorbed by them, and probably cannot be quantitatively separated. The molecular weight of asphaltenes is very high ranging from 1,000 to 2,000,000, depending upon the method and conditions of measurement. They are generally spherical in shape, with a diameter of 30 to 65A varying from source to source [8]. A number of investigations have been made to determine the model structure for asphaltenes and resins by physical methods like IR, NMR, ESR, VPO, GPO, mass spectroscopy, x-ray, electron microscopy, and by chemical methods including oxidation and hydrogenation.
The asphaltene structure, in it's natural state, exists as a complex of secondary structures, which enables the asphaltenes to move with the crude into the well bore. The core of this structure is a group of unit plates, four to eight in number, stacked together. This face to face association is induced by a secondary weak bonding force between faces of the condensed aromatic ring structure [8]. Each unit plate has a long chain of paraffinic residues attached around its outer edge; therefore, the structure might appear as a spherical core with a coating of the paraffinic chains on the outside.
Asphaltenes Chemical and Physical Properties. The amorphous, polar asphaltene molecules do not have melting points and decompose on heating above 300-400 0C. In nature, asphaltenes are believed to be the final product of oxidation of polycyclic aromatic hydrocarbons and natural resins. On the other hand, hydrogenation of asphaltic compounds produces heavy hydrocarbon oils containing polycyclic aromatics. Asphaltenes cannot be separated into individual components or narrow fractions. They are lyophilic with respect to aromatics, in which they form highly scattered colloidal solutions and lyophobic (especially asphaltenes with low molecular weight) with respect to paraffins like pentanes and petroleum crudes. Asphaltenes are most commonly thought to occur in the form of colloidal dispersions; however, they tend to cluster into aggregates. The state in which asphaltene particles can be found in petroleum fluids depends largely on the presence of other particles in crude oil, like resins, aromatics, paraffins, etc. [10]. A commonly accepted view in petroleum chemistry literature is that crude oil asphaltenes form micelles that are stabilized by absorbed resins kept in solution by aromatics. Asphaltene particles, which have been found to be charged, can associate with the resin or maltene components of the oil through electrostatic, polar, and dispersion interactions. The aromatic portion of the resin adsorbs onto the aggregate’s surface, while the aliphatic portion projects into the oil phase [11]. By bridging between the large polar core of the asphaltene particle and the surrounding non-polar oil, the resins stabilize the asphaltene dispersion and form an asphaltene-resin micelle.
Asphaltene Flocculation
Flocculation of asphaltene in crude oils is known to be irreversible. This is the major cause of blockage damage to the flow of petroleum fluids. Due to their large size and their adsorption affinity to the solid surfaces, flocculated asphaltenes can cause irreversible deposition [6].
Parameters Controlling the Stability of Asphaltene Micelles in Crude Oil. Two key parameters that control the stability of asphaltene micelles in crude oil are the ratio of aromatics to non-polar saturates and the ratio of resins to asphaltenes. When these ratios decrease, asphaltene micelles will coalesce and form larger aggregates. Relatively large asphaltene particles may flocculate out of solution in the presence of excess amounts of paraffin hydrocarbons [2].
The flocculated asphaltene will precipitate unless there are enough resins in the solution to surround the asphaltene particle and form steric colloids. Experimental evidence suggests that there is a critical concentration of resins below which the asphaltene flocculates would precipitate [11]. Asphaltene and its flocculates are known to be surface-active agents. This characteristic was used to develop an experimental technique based on the measurement of oil/water interfacial tension to detect the onset of asphaltene precipitation.
Asphaltenes Deposition
At “normal” reservoir conditions asphaltenes, resins, maltenes, and oil phase are in thermodynamic equilibrium. The precipitation and deposit of asphaltene is generally caused by a change in conditions and/or environment surrounding the crude. Since asphaltenes are stabilized as colloidal particles peptized by resins, any actions of chemical, mechanical or electrical nature that depeptize these particles will lead to precipitation. In general the lower the API gravity of the crude, the more asphaltene present, e.g., crude of 9 API gravity contains about 82% asphaltene, whereas a crude of 41 API gravity contains only about 3% asphaltene. However, in evaluating a given oil for potential asphaltene precipitation problems, the ratio of resins to asphaltenes is more important than the absolute asphaltene content, since the resins are thought to stabilize the asphaltenes in solution [12]. Therefore, crudes with high ratio of resins to asphaltenes are less likely to cause deposition problem than crudes with large amounts of non-polar saturates with aromatics. In the production systems, changes in temperature, decline of the reservoir pressure or change in chemical composition of the crude by addition of miscible solvents to the oil, combined with the streaming-potential effects in the well tubing, affects asphaltene solubility.
Asphaltene Deposition Due To Chemical Means. Addition of aliphatic/low surface tension liquids like pentane, hexane, petroleum naphta or gasoline, light crude will precipitate asphaltenes by solubilizing resins in the bulk oil phase. Many asphaltic oils react rapidly and irreversibly with strong acids to produce a heavy sludge due to pH changes [5]. This sludge is insoluble in even the best solvents available. As a result, acid treatment in a well may case severe loss in permeability that could require refracturing or recompletion of the well. Asphaltenes deposition can also occur when solvents are used to displace oil in enhanced oil recovery. In the reservoir, displacing fluids such as carbon dioxide can lead to asphaltene deposition.
With respect to solvent, it is generally agreed that the severity of precipitation increases with decreasing carbon number of the solvent, except where the solvent strips the oil of asphaltenes rather than dissolving them in the oil [1]. The transfer of resins to the oil phase facilitates the flocculation and precipitation of destabilized asphaltenes.
Asphaltene Deposition Due To Electrical Means, Cooling and Pressure Drop. Asphaltenes will start depositing at the formation due to cooling and electrostatic effects. When a crude oil flows in a conduit (porous media, well, pipeline, etc.) there is an additional effect (electrokinetic effect) to be considered in the behavior of its heavy organic constituents [6]. This is because of the development of electrical potential difference along the conduit due to the motion of charged particles. This electrical potential difference can cause a change in charges of the colloidal particles further down the pipe. The ultimate result is their deposition and plugging of the conduit. The factors influencing this effect are the electrical and thermal characteristics of the conduit, flow regime, flowing oil properties, characteristics of the polar heavy organics and colloidal particles.
Laboratory tests have indicated that variations of pressure exerted on a petroleum fluid can cause the deposition of heavy organic contents. When crude oil moves from the formation into the wellbore, there is a significant pressure drop which may cause gas phase separation, and as a result, heavy organic deposition [10]. Similar effects can be found at the pump intake screens and in tight hole, high volume applications where high pressure drop across the motor may occur.
Pump intake screen. It is customary to use a screen at the pump intake to prevent entry of debris to the pump. ESP systems are normally operating under close to minimum required pump intake pressure, and any additional pressure drop can cause the first impeller to operate below bubble point. Normally, 50% of the impeller vein opening is used for screen mesh. In normal applications where no asphaltenes or scale problems are expected, this type of screen is sufficient. In asphaltenes applications it is important to reduce pressure drop across the screen to minimum, or eliminate the use of a screen if possible. Reduction of pressure drop across the screen can be achieved by increasing the total opening area. It can be done in two different ways: using wedge wire screens or special high screen area intakes.
Tight hole, high volume applications. These are extremely difficult applications especially in 4.5" casings where the only available equipment type is a combination of 375 motor (3.75" motor OD) and 338 pumps (3.38" pump and intake OD). The difference between motor OD and casing drift diameter in the range of 0.100 to 0.200" is accepted as a normal application. In some cases this can be as small as 0.050". High pressure drop across the motor can cause asphaltenes to precipitate from the fluid, and then build up on the motor stator and seal section. This reduces the heat transfer from the motor and thrust bearing. It restricts fluid production, and in a worse case scenario can completely stop fluid flow required for motor cooling.
Bubble point. Bubble point is a pressure at which gas separates from solution. The fact that the deposition depths for most of the wells are generally less than, but close to the bubble point depth indicates that the pressure drop plays a stronger role in asphaltene deposition than the other factors. This is critical in ESP applications since they are mostly operating at flow reducing the fluid level very close to pump-off conditions with Pump Intake Pressure close to bubble point.
This situation is further complicated because the pressure and temperature changes with tubing depth as well as at every pump stage. There is considerable agreement that the greatest precipitation occurs at the bubble point. Above the bubble point there is no change in oil composition while below it the evolution of gas increases the average molecular weight and polarity of oil causing the asphaltenes to flocculate and begin to drop out of solution [6]. As the oil and gas leave the formation and go up the well, the pressure and temperature will continue to drop and hydrocarbons will continue to be deposited throughout. It is important to note that once a thin film layer of hydrocarbon deposit is formed on the surface, the rate of further deposit accumulation is drastically increased, thus a typical production drop curve associated with clogging is observed. Identification of asphaltene precipitation zones as a function of temperature and pressure are of great interest.
Asphaltene Deposition Due To Mechanical Means. Drilling, completion, stimulation, and hydraulic fracturing operations can trigger the onset of asphaltene precipitation in the vicinity of the well. Stripping of resins from around asphaltene particles can also occur by shearing in pumps, formation, perforations, and valves/chokes [2].
Multistage Centrifugal Pumps with radial flow stages. This type of pump stage is most susceptible to asphaltene plugging. They have a very small vein openings and vein height. The same production rate can be achieved with higher flow stages operating at lower speed. The most desirable is mixed flow stages. This reduces the shearing inside the stages by reducing the fluid velocity and change in flow direction (180deg change in flow direction with pancake stages).
Coating of internal pump and intake components. Most of the internal pump and intake components are made by sand or resin casting. Coatings are the most economical means of eliminating casting surface imperfections and produce a surface with low friction and good release properties.
Damage Caused by Asphaltenes Deposition
Asphaltenes can form deposits anywhere in the oil production system. These deposits can be found in the near-wellbore formation, on the downhole-submersible pumps, and in the tubing, flowlines and production-handling facilities.
Damage in ESP Equipment. Asphaltenes deposition on or in ESP equipment can reduce the "run time between failures". The failures caused by asphaltenes deposition are complex and asphaltene deposition on or inside one of the ESP component cause catastrophic failure of other components.
Asphaltenes deposition on the motor surface. The deposition on the motor reduces heat transfer and can cause motor overheating. It can result in mechanical or/and electrical motor failure. The mechanical failures are mostly cause by
loss of oil viscosity which results in loss of radial or/and axial shaft support.
Bearings. The ESP motors used journal / sleeve bearings to provide radial support and thrust bearings to support load from rotor weight. One of the main concerns regarding the efficient operation of ESP motors is ensuring adequate lubrication of the rotating components. Hydrodynamic lubrication involves the complete separation of stationary and rotating bearing components by a lubricant film. If the unit is operating at higher than recommended temperatures, the viscosity of the oil will decrease and bearings will have inadequate load-carrying capacity. The film thickness developed between the journal and bearing, or the thrust bearing and runner, will be too small to prevent contact of the surfaces. Introductions of fine brass particulates into the lubricating fluid from mechanical bearing wear will greatly affect the protective film layer. Then the avalanche scenario starts. As the oil circulates up through the center of the shaft, through the oil holes in the bearing and out over the rotors brass will plug the lubrication holes in one of the bearings. The bearings above and below this location will still receive lubrication. The plugged bearing will continue to operate but be starved for necessary lubrication resulting in an increase in friction, overheating, possible seizure and/or arcing to the stator.
If the temperature is extremely high, the oil itself may burn and lose all insulating and protective capabilities. Temperature effects are visible on a microscopic and macroscopic level. Microscopically, high temperature can affect the alloying elements of the bearing materials. The difference in coefficients of thermal expansion of these elements will result in grain distortion and possible cracking along grain boundaries. The severity of cracking will depend on the mechanical wear and temperatures encountered. Macroscopically, the damaged surface and surrounding areas of the affected bearings will have a burnished or blackened appearance, and may be covered by a varnish deposited by the deteriorating oil.
Besides compromising lubricity of oil, brass will compromise dielectric strength of oil which will cause electrical short within motor. This mostly occurs at I-block electrical connection or end-coil and PHD wire splices.
Thermo-expansion. Motor operating at normal condition is maintaining thermal stability between rotor and stator. Ones the heat transfer from motor to well fluid is disturbed, rotor has tendency to overgrow the stator. On top of that, epoxy in the stator will swell up and rotor rub wills occur. Bearing seizure and/or arcing from the stator to the bearing or/and phase to phase electrical stator short will happen.
Asphaltenes deposition on seal surface and internal components. The seal section connects the drive shaft of the motor to the intake shaft. It allows for expansion of the dielectric oil. Temperature gradient resulting from both the ambient and motor temperature rises will cause the oil to expand and expansion must be taken in the seal. If the heat transfer to the well fluid is compromised by asphaltene deposition on the seal housing, the expansion capacity of the seal section cannot be sufficient. In that case, the seal section will no longer isolate the well fluid from the clean motor oil. Another function of the seal section is to equalize the casing annulus pressure with the internal motor pressure through the communication hole in the head of the seal. This way the motor is protected from a leakage past the sealed joints. If this hole is plugged with asphaltenes, the seal is no longer able to equalize pressure during the oil contraction and a vacuum is generated inside the motor causing leakage throughout the sealed joints. A combination of excessive heat and excessive pressure cycling will reduce bladder strength and can result in its rupture. The positive barrier to the well fluid provided by the bladder will be eliminated. The contamination of the motor oil with well fluid will lead to bearing and motor insulation failure.
Bearings. The presence of water in the motor and seal section has a significant impact on the lubricant. It can act as a corrosive element and will dilute the lubricating oil. Dilution of the oil results in a decrease in protective film, and mechanical wear of the bearings will begin. As the oil circulates up through the center of the shaft through the oil holes in the bearing and out over the rotors, it combines with the water to form an emulsion. Entrapped in this emulsion will also be any fine particulates that have entered with the water or from mechanical wear. This emulsion will cause an increase in operating temperature in the motor and seal section thrust bearing and will cause further damage.
Asphaltenes deposition inside and on the surface of Rotary Gas Separator (RGS). The RGS is using centrifugal forces to separate the free gas from the well fluid before entry into the pump.
Plugging. Asphaltenes deposition can plug intake ports, intakes screens, cross-over or exhaust ports. Plugging of intake screens or intake ports causes pump cavitation, and finally, pump mechanical damages and motor overheating due to loss of fluid flow on top of the motor. Plugging of cross-over or/and exhaust ports will compromise RGS's ability to separate free gas, and gas locking or upthrust wear (depending on volume of free gas entering pump) will occur. Motor overheating due to loss of fluid flow on top of the motor will be a potential mode of failure.
Unbalance. Uneven asphaltenes deposition inside the rotor will cause its unbalance resulting in high seal and pump shaft vibrations. Excessive pump stages radial wear will occur which will cause pump to loose the ability to lift fluid to the surface due to high hydraulic leakage in stages. Motor overheating due to loss of fluid flow on top of the motor will be a potential mode of failure.
The seal section contains multiple mechanical shaft seals which keep the well fluid from leaking down the shaft. High shaft vibration compromises the mechanical seals' ability to prevent leakage, and well fluid will contaminate the motor which will lead to bearing and motor insulation failure.
Asphaltenes deposition inside the pump. Partial pump stage or discharge plugging increases the thrust developed by stages. In a compression style pump, the thrust load is transferred through the shaft to the thrust bearing in seal section. Excessive thrust load will overload the thrust bearing and result in its failure. Once the thrust bearing has failed, the thrust load is no longer transferred to seal section and excessive downthrust wear of pump stages occurs. A similar scenario will occur with a "floating impeller" type of pump, once impellers are locked to the shaft due to asphaltene deposition. Finally, motor overheating occurs once the pump is completely plugged or it has lost the ability to lift fluid to the surface due to downthrust wear of pump stages. Asphaltene deposition within the stages, especially in its journal bearing, will produce excessive shaft load or shear off the pump drive key. In both cases, pump and motor failure will occur.
Cable failure due to excessive heat. MLE insulation and its splices to power cable and pothead integrity can be compromised by excessive heat produced by motor or thrust bearing in the seal section in any of the cases listed above.
Once oil is produced, the asphaltene problem continues. Asphaltene deposition around the well tubings, flowlines, separators, pumps, storage tanks, transfer pipelines and other equipment has in many cases increased the cost of production considerably.
Control and Removal of Heavy Hydrocarbon Deposits
Heavy organic deposition due to asphaltene flocculation can be controlled through better understanding of the mechanisms that cause it in the first place. Asphaltenes can be destabilized in any area of an oil production facility from the near wellbore region to as far as the refinery feed stock. Altering production processes and using chemical treatments can control flocculation and deposition of asphaltenes. The well completion with ESP equipment required some modifications compared to standard ESP completion. They include the use of Variable Speed Controllers (VSC) combined with an oversized pump, increased impeller vein height, internal pump coatings, reduced pressure drop at the pump intake and chemical injection via capillary line.
Modification of Production Techniques. The modification of production techniques include reduction of streaming potential, elimination of incompatible materials from asphaltic crude oil, minimization of pressure drop in production equipment and alteration of standard well completion techniques.
Reduction of shear. Internal pump coating is a relatively new method to prevent asphaltene depositions by reducing porosity of the down hole pump components, preventing turbulent flow, reducing streaming potential, and eliminating absorption sites. Two families of resins, Polytetrafluoroethylene (PTFE) and Hexafluoropropylene (FEB), are presently used in the ESP industry. They are applied as a thin film of fluoropolymer coating in applications where high release (non-stick) properties are required. FTFE resins, especially have exceptional resistance to deposition of asphaltenes on downhole equipment.
Elimination of incompatible materials from asphaltic crude oil streams. It is suggested that all fluids used in well stimulation, injection and enchanced recovery should be tested for static and dynamic compatibility with the reservoir fluids prior to operations.
Minimizations of pressure drop in the ESP equipment. Increasing screen area for the same screen mesh can minimize pressure drop at the intake pump utilizing screens. Increased area of the screen will reduce fluid velocity across the screen and consequently minimize the pressure drop. Production tubing quality can also influence pressure in the production facility. Rough tubing surfaces generate turbulent flow that can cause pressure drops. In many cases replacement of old tubing with new can eliminate asphaltene deposition in the production string due to pressure drop.
Modification to the standard well completion techniques. The use of standard well completion techniques in cases where heavy organic deposition was suspected quite often resulted in costly workovers for deposit removal. To prevent this and improve control of chemical injection, completing wells with a dual completion is advised. The second tubing string or capillary line can be attached to the production string or be incorporated into the ESP power cable. An ESP power cable with a capillary line will allow injection or circulation of solvents or dispersants when necessary. Capillary Line ESP Power Cables are designed to operate over a broad temperature range. These cables use a unique method that incorporates the capillary tube along with the power cable that eliminates the cost of running a second chemical treatment line down the well [13]. It is important to remember that the chemical must be injected below the motor to allow enough time for chemical reaction to occur before production fluid enters the pump intake. This technique allows for proper well chemical treatment without the ESP being shut down.
Solvent Treatment. Solvent treatment of the oil is considered to be beneficial in some cases because it dilutes the crude oil and reduces the tendency of the heavy organics to precipitate. Solvents are among the most popular methods of heavy hydrocarbon removal. This treatment, however, may not be very successful largely because the solvents that can be used are limited to aromatic solvents like benzene, toluene, ethylbenzene and xylene. Xylene is generally the most common solvent used in well stimulations, workovers, heavy organics inhibition and cleaning. Injection of xylene through a non-producing string may actually help to minimize asphaltene deposition problem. When solvents come in contact with organic deposits, they continue to dissolve the deposits until the solvents reach their saturation level. If the solvents are not removed from well promptly after their saturation level is reached, then some of the dissolved asphaltene will precipitate out of solution. Sometimes this leads to worse clogging problems than before the treatment, due to agglomeration of deposits in the areas that did not previously have any deposit problems. Therefore, solvents should be handled with caution and be removed at the right time. In oil fields with frequent need for aromatic wash it may be necessary to design an aromatic solvent with stronger wash power and better economy for a particular deposit. Solvents containing BTEX are encountering strong resistance due to environmental concerns and government regulations. These problems are especially acute for offshore applications. Laboratory tests may be helpful to develop the most effective, economic and environmentally friendly blend of aromatic solvents for a given oil field. Some new products that can replace BTEX solvents have become available on the market, which offer safe, economical and effective solutions to heavy hydrocarbon deposits. It incorporates the advantages offered by traditional solvents, dispersants and inhibitors into a single source solution [7].
Dispersant Injections. Dispersants are also among the popular methods for removal of asphaltene deposits. They are especially effective in crude oils where the ratio of resin to asphaltene is not high enough to prevent asphaltene flocculation. Dispersants work in a manner similar to the resin activities in the natural environment. They both surround the asphaltene molecules and prevent their flocculation and deposition. Dispersants do not dissolve asphaltenes particles but disperse them in the oil or water through the surfactant action. They are usually added to the crude or to water before they are injected and circulated [12].
Case Study - Oil Fields with ESP Completion in Alberta, Canada
Chemical treatments. It used to be standard procedure for chemical treatment to shut wells down and soak pumps. In some cases, ESP's were unable to restart after pump soaking. In that case, the only option was to use endless tubing to try to free the pump. This common practice was very expensive and seldom successful.
Chemicals recirculation. In 1995, Shell started to treat wells without shutting them in. Instead of shutting the well down, fluid recirculation is used. Refromate is pumped down the annulus at a rate that is enough to push the oil to the pump intake and then recirculated with the flow line choke approximately at 90%. This helped dramatically to prevent the ESP pump stacking.
Chemical treatments via capillary lines. The miscible flood project in Swan Hills, Alberta, has been subject to severe asphaltene deposition problems after the breakthrough of the miscible flood front. Many wells required high content aromatic solvent formation squeezes, wellbore, pump and tubing clean outs to maintain production levels. The asphaltene problem was so bad in some wells that the frequency of treatments in one case was about every few days. This generated a need to reduce the cost of the asphaltene treatment control program. In an effort to provide a cost-effective alternative for these wells deposition problem, solvency and dispersant tests were used to screen a number of products to determine their effectiveness. Based on this testing, the treatment design for this asphaltene problem was an initial wellbore cleanup with aromatic solvents followed by continuos injection of asphaltene inhibitor, to a site just below the ESP motor (to give the chemical some retention time) via a capillary injection string. Four different runs of capillary line with injection from surface were done at different locations. Major difficulties were the banding on tubing problems and sulfide stress corrosion cracking of capillary lines. No check valves or screens were originally installed at the surface tank and chemical pump which resulted in the plugging up of capillary lines. It was found that the chemical pump should not be shut down for any longer than the time required to do maintenance on the equipment. It was found that most line plugging occurred when the system was shut down. The solution to this problem is switching from chemicals to a solvent and decreasing the pump rate. The pump rate must be high enough so that any suspended particles will not settle on top of the check valve.
Use of Variable Speed Controllers (VSC) combined with oversized pump. The next step after improving chemical treatment procedures was to incorporate a VSC into "Asphaltenes Program". Since all of Shell's wells with potential asphaltene problems were operated by a VSC, Shell decided to try and run larger vein pumps but operate them at 40 to 50 Hz without compensating production. As an example, the run time between failures was improved from 150 days to 564 days run just by switching to large vein, mixed flow stages.
Coatings. Coated stages, intakes and discharge have been a huge contributor to the success of combating asphaltene. Impellers and diffusers are made by sand casting and internal components cannot be machined. This allows the asphaltene and scale to build up on these surfaces. One well needed as much as 17 xylene treatments in one year to free stacked pumps and the effects were not satisfactory. On January 3, 1996, a large vein, coated pump was installed. Coating was also done internally on the gas separator and 10 joints installed above the pump’s discharge head. No chemical treatments have been needed on this well since the coated, oversized ESP system running at low speed was installed. Operation has been smooth with little downtime or production losses. A total run time of 1024 days was achieved as compared to 487days average run for this well. The pump was a 163 stage GC1700 and it operated at just below 50Hz. The production rate was 175m3/D with 93% water cut and 6000M3/D of gas. This well is producing API34.5 oil. Other operating parameters as listed below: BHT - 110C; reservoir pressure - 27,500kPa; pump depth - 2750m, perforation depth 2800m.
Conclusion
The problem of asphaltene deposition during the recovery and production of crude oil is both costly and troublesome. Asphaltene can be deposited in any area of an oil production facility, but the most damaging place for asphaltene to deposit is in the near wellbore area and inside the ESP pump. Heavy organic deposition due to asphaltene flocculation can be controlled through better knowledge of mechanisms that cause the deposition in the first place. The composition of crude and the behavior of asphaltic crude play an important role in asphaltene deposition. Crude oils with high resins and maltenes content are more stable. Changes in temperature, pressure drop and electrokinetic effect due to build up of electrical potential difference along the conduit can influence the thermodynamic equilibrium of oil and cause asphaltene deposition. Early diagnosis of the crude tendency to precipitate asphaltenes and the prevention of these deposits may seem costly at first, but the costs may considerably increase once the deposition takes place. In severe cases it may not even become economically possible to continue the production.
Besides old treatment methods for asphaltene deposits, new methods to prevent asphaltene deposit in ESP equipment have been developed. They include the use of Variable Speed Controllers (VSC) combined with oversized pumps operating at lower speed, increased impeller vein height, internal pump coatings, reduced pressure drop at the pump intake by incorporating new screen styles and/or new intake designs. The use of an injection capillary line and fluid recirculation enhances standard methods of well chemical treatments.
The best measurement of improvement in operating ESP's in asphaltene fields is the reduction in chemical jobs and increase in runtime due to the above mentioned changes. We do not believe it was solely one change that drastically improved the runtime but a combination of several.