The formation of stable heavy oil emulsion, which may upset separation facilities and eventually lead to production impairment, is one of the most common issues encountered in the development of heavy oil reservoirs. This paper investigates the influence of various physicochemical parameters, including water cut, polymer status (sheared/unsheared), polymer concentration, demulsifier type and concentration, and the coexistence of polymer and demulsifiers on the stability of heavy oil emulsion. The viscosity of heavy oil emulsion is also studied at various water cut and polymer concentration. In this study, water-in-heavy oil emulsion was prepared at the water cut of 30% as the blank sample using heavy oil with API gravity of 14.5° and the synthetic brine. The effect of the water cut was investigated by both the bottle test method and multiple light scattering (MLS) method to validate the effectiveness and reliability of the MLS method. The other parameters were studied only through the MLS method. The results showed that the increasing water cut resulted in the decrease of heavy oil emulsion stability and could potentially invert the stable w/o emulsion to loose o/w emulsion at the phase inversion point where the emulsion viscosity peak occurred. Adding polymer, regardless of the polymer status, tended to reduce the stability of heavy oil emulsion, and the unsheared polymer contributed to less emulsion stability. However, the influence of polymer concentration was rather complicated. The emulsion stability decreased as polymer concentration increased, and further increasing polymer concentration enhanced the emulsion stability. A similar trend was also evidenced by emulsion viscosity with increasing polymer concentration. The addition of three oil-soluble emulsion breakers was able to break the heavy oil emulsion efficiently, whereas the water-soluble demulsifier had little demulsification effect. Furthermore, there existed an optimal concentration for the selected oil-soluble demulsifier to achieve the maximum separation. Although polymer itself could intensify the destabilization of heavy oil emulsion, it hindered the destabilization process of the heavy oil emulsion when the oil-soluble demulsifiers were added. This study will provide a comprehensive understanding of the factors affecting heavy oil emulsion stability.

Asphaltene precipitation and deposition occur in the reservoir, near-wellbore, inside the tubing, and production facilities during primary, secondary, or tertiary production. As more water-flooded oil fields produce under miscible gas flooding, this problem becomes more common around the world. If asphaltene deposition occurs in the reservoir or wellbore, it can severely affect the economics of the field in terms of production loss, intervention cost, and the requirement for chemical additives, if necessary. In some severe cases, intervention would be impossible and side-track well needs to be drilled. Hence, the best strategy for oil production in asphaltenic reservoirs is to control asphaltene precipitation and deposition through prevention and remediation jobs to minimize the number of well shut-ins, the downtime of the wells, and the associated cost. In this paper, we reviewed the common asphaltene prevention and remediation techniques along with their pros and cons. Since removing asphaltene deposits from the problematic wells is relatively expensive and sometimes requires substantial downtime of the well, we focused on one of the prevention techniques ( i.e ., continuous solvent injection through capillary injection string), which has become more popular, to control asphaltene precipitation in the wellbore. We obtained the physical properties of an aromatic solvent from literature and then characterized it as a component to be used with PC-SAFT EOS. Subsequently, we used the in-house wellbore model to evaluate the effectiveness of the continuous solvent injection with different injection rates on preventing asphaltene precipitation and deposition along the wellbore.

Seawater injection is widely used to maintain the offshore oil reservoir pressure and improve oil recovery. However, injecting seawater into reservoirs can cause many issues such as reservoir souring and scaling, which are tightly related to the seawater breakthrough percentage. Accurately calculating the seawater breakthrough percentage is important for estimating the severity of those problems and further developing corresponding strategies to solve those issues. The validation of using natural ion boron as tracer to calculate seawater breakthrough percentage was investigated. Boron can interact with clays, which can influence the accuracy in seawater breakthrough calculation using boron. Therefore, the interaction between boron and different clays at various conditions were studied, and Freundlich adsorption equation was used to describe the boron adsorption isotherms. Then boron adsorption isotherms were coupled into the reservoir simulator to investigate the boron transportation in porous media, and the results in turn were further analyzed to calculate the accurate seawater breakthrough percentage. Results indicated that boron adsorption by different clays varied. pH value of solution can significantly influence the amount of boron adsorbed. As a result, the boron concentration profile was delayed in coreflood test. The results of reservoir model fit perfectly with that of coreflood test, indicating the validation of boron reaction model. Based on the reservoir simulator results, boron concentration profile in produced water was successfully used to calculate seawater breakthrough percentage by considering the clay content distribution. However, the seawater breakthrough point cannot be calculated by boron as boron concentration is still at the formation level due to boron desorption.

In-situ extraction of heavy sulfured oil based on steam injection comes with a high level of risk in terms of H2S production, resulting from aquathermolysis reactions. This could lead to on-site living being casualties, environment damage, surface facilities and wells corrosion. Also, there is a strong need to understand aquathermolysis reactions and to forecast acid gases generation in such context. For that aim a tailor-made workflow was developed to estimate H2S concentration at the well-head. To meet these challenges, a 3-steps approach combining laboratory studies and numerical predictions has been developed. It firstly consists in a fast preliminary assessment of the highest H 2 S risk areas, based on the measurements of sulfur characteristics of reservoir core samples using our Rock-Eval Sulfur set-up. Then aquathermolysis experiments from the previously selected core samples are conducted in order to calibrate the compositional chemical model of the reservoir simulator. The latter is eventually used to carry out thermal compositional reactive simulations at field scale. The reservoir simulator allows simulations of SAGD processes and handles H 2 S distribution over oil/water/gas phases and its migration in these phases. Simulation results show that acid gases are generated within the steam chamber, before they accumulate at the chamber edges where they dissolve in the water and oil phases. This contributes to reduce viscosity, allowing the oil to flow along the steam chamber edges before it has reached the steam temperature. Therefore the H 2 S produced at surface is mainly carried towards the wells by water and to a lesser extent oil. This flowing oil has not reacted with the steam: its composition is close to the initial reservoir oil but enriched with dissolved gases. The steam chamber shape, the temperature distribution and the H 2 S produced at surface are strongly modified when heterogeneities are introduced in the reservoir model. Synthetic cases allow a deeper understanding of the effects of heterogeneities. Vertical permeability is thus found to be a key factor of H 2 S production variations. When steam reaches a lower permeability lithology, a delayed rise in H 2 S production at wellhead is observed as aquathermolysis reactions rates increase. Finally Foam Assisted-SAGD has been considered. While the foam improves the Steam-Oil ratio, no clear improvement was observed regarding the H 2 S production.

Heat generation in the reservoir by means of electromagnetic wave stimulation offers innate advantage with efficient energy introduction. Transmissibility of heavy oil and bitumen are predicated on decreased viscosity through temperature rise, which makes microwave heating a plausible candidate. This study focuses on identifying the components of the crude oil which primarily contribute to heat generation under the influence of the microwave. Pinpointing what makes the oil a more effective microwave receptor enables the optimization of desirable traits in the oil phase. Three different oil samples were selected due to variations in both physical and dielectric properties. Fractionations were then performed on each oil to isolate the contribution of each SARA (saturates, aromatics, resins, and asphaltenes) constituent. Dielectric constant and loss index, which together represent complex permittivity, were measured by utilization of a vector network analyzer (VNA) with a dielectric probe. Complex permittivity of both the bulk oil as well as each fraction were measured for all three oil samples. Also, investigation into asphaltenes behavior in the oil, either precipitated or dispersed, was performed by introducing varying dosages of both precipitating agents (nC5, nC7) and a dispersant (toluene). Within the oil phase, the mutual attraction that is realized by the more polar components, namely the resins and asphaltenes, creates complexities in the absorption behavior. Net cancellation of the individual polarity is evidenced by the non-additive nature of the deasphalted oil and asphaltenes. The attraction between the resins and asphaltenes is further illuminated by inspection of the dielectric response in the presence of the precipitating agents. Removal of asphaltenes through precipitation corresponds to the freeing of interacted resins. The contribution in polarity of the previously cancelled resins is evidenced by an increase in the dielectric constant with increasing precipitating dosage. Both oil C2 and C3 achieve the identified behavior stemming from an asphaltene weight percent comparable to that of the resins. However, upon analysis of the oil C1, the opposite trend is achieved. Unique to oil C1 is a very large weight percent of asphaltenes. Therefore, the oil has excess asphaltenes which aren't interacting with the resins. Precipitation preferentially occurs from those asphaltenes not being interacted as they are relatively less stable. Net cancellation of all resins remains untouched and no resins are freed as a function of the precipitation for oil C1. The foundational impact of polarity on absorption characteristics provides the potential to investigate the efficacy of microwave introduction specific to each fractionation. Experimental results from dielectric property measurements showed that the polar fractions of the crude oil, resins and asphaltenes, heavily influence the effectiveness of microwave heating. For the first time, the contribution of individual SARA fractionations to microwave efficiency was investigated.

Most North Slope Alaska oilfields undergo waterflood for pressure maintenance and improved oil recovery. Both recycled produced water, as well as treated seawater are injected into the reservoir which then mixes with connate water in the formation. The combination of seawater with connate water in the reservoir can lead to severe barium sulfate and calcium carbonate scaling in the production wells and reservoir. The scaling is particularly severe at initial breakthrough of the waterflood front in the production wells. However, since water breakthrough timing is unknown, most scale inhibition techniques commence after observing first water production, which is often too late. This scaling can cause significant production losses, leading either to costly remediation with acid, or in the case of barium sulfate, may be impossible to repair. A novel scale inhibition technology which uses scale-inhibitor infused proppant has been applied to mitigate scale in other North American oil and gas fields. Unlike the North Slope fields, most of these wells must be inhibited from first production to prevent scale formation from the start. The technology uses a novel process whereby scale inhibitor is only released when it comes in contact with water, making it a choice option for use in North Slope fields where scale inhibitor must be in place at waterflood breakthrough, which is typically unknown. One operator elected to install this technology in the Oooguruk field in Alaska. The Oooguruk field is an undersaturated oil reservoir found on Alaska's North Slope. Development includes both production and water injection wells, arranged in a line-drive pattern. Wells are drilled horizontally and completed with multistage hydraulic fracture treatments, which are designed to create longitudinal fractures along the wellbore. Water injection is initiated in the injectors immediately after post-frac flowback operations. Based on the severe scaling observed in other area fields, engineers deemed it imperative to put a plan in place to address scaling when waterflood breakthrough occurred. Since these are horizontal wells, scale remediation is difficult (if not impossible) to perform once the scaling damage has occurred. To address this problem, the novel scale inhibitor proppant technology was incorporated in the hydraulic fracture treatments of the producers. Four wells employing these treatments were successfully completed in 2015 and 2016. Testing of the water during the fracture clean-up period showed inhibitor returns as expected, tailing off as the load water was produced. In early 2018, the first waterflood breakthrough occurred on several wells, and the produced water was analyzed and found to contain inhibitor levels above the minimum designed inhibitor concentration, thereby successfully providing immediate scale inhibition to the entire wellbore. This paper will review the proppant delivered scale inhibitor technology, document the field application including the project analysis and design, and present the inhibitor results. This is the first installation on the North Slope of a scale inhibitor technology that can effectively remain dormant, and successfully inhibit scale upon waterflood breakthrough years later. In this case history, the scale inhibitor proppant is inhibiting water that did not break through until 2-3 years after placement. This paper will be beneficial to completions and production engineers who wish to prevent the detrimental effects of scale in their production wells, particularly in waterflood operations.

Scale deposition has been a significant problem in the oil and gas industry. Scale deposition has an adverse impact on production and injection operations. The precipitation of scale in the near-wellbore area will diminish the productivity of the production wells and loss of the injectivity of water injection wells. This paper presents a new non-corrosive agent to remove calcium carbonate, and calcium sulfate scales. Two sets of coreflood experiments were conducted to evaluate the chemical to remove anhydrite depositions. Coreflood experiments were conducted by using the new scale remover to stimulate dolomite cores with anhydrite content of 30 wt% at 250°F. Other experiments were conducted with the Bandera sandstone cores. Calcium sulfate was precipitated inside the pores and then the chemical was used to treat the cores to remove this damage. Effluent samples were collected and analyzed with ICP for sulfur and calcium concentrations. CT scan was used to detect the dissolution and the deposition of scale inside the cores. The chemical was applied on several oil wells from the Nukhul sandstone formation. Coreflood results show increasing the permeability of the dolomite core to 4 times of its initial value and ICP results show 1:1 calcium to sulfur concentrations. The second coreflood experiments showed the ability of the dissolving agent to remove the precipitated scale completely with (final permeability =initial permeability) with no effect on clays. In the field case, the treatment was conducted and placed using a coiled tubing without using additional additives such as corrosion inhibitors, intensifiers, and iron control agents. The success of this treatment was realized by increasing the well production 4 times its initial oil production per day. Field data and the lab results highlight that the de-scaling solution is an effective fluid for calcium sulfate scale.

Viscoelastic surfactant (VES) have been successfully applied as acid-diversion fluids. However, high temperature, interaction of VES and Fe(III), addition of alcohol-based additives, and chelating agents all interfere with the apparent viscosity of the VES-based acid and reduce its efficiency. In the present study, the interactions of Fe(III) with a new type of VES-based acid system, which can be applied effectively for diversion at high temperatures, were characterized in a wide range of pH. The physical behavior of the VES solutions after addition of iron at various pH values were observed visually to determine any change in the viscoelasticity of the solutions. In the present study, because of the similarity between chemical structures, 3-sulfopropyldimethyl-3-methacryl -amidopropylammonium (SMA) was used as a model compound of VES to characterize the nature of the interaction between VES and Fe(III). IR spectroscopy was employed to understand the nature of the SMA interactions with Fe(III) in different pH values. Also, UV-vis spectroscopy was conducted to determine stoichiometry of the interactions as well. Single X-ray crystallography was also utilized to further understand the nature of interaction between SMA and Fe(III). Bottle test results show the formation of a viscoelastic gel at different pH in the presence of Fe(III)and VES. IR results express that the interaction of SMA and Fe(III) occurs through the amide group in the SMA which is existed in the headgroup of tested VES too. These results confirms previous observations that the interaction of amide part of the VES with Fe(III) results in screening the repulsion forces between surfactant head groups and formation of wormlike micelles that is the primary reason for increase in the viscosity. Results of continuous variation method on SMA and Fe(III) also confirm the 1:1 stoichiometry in their interaction which are in agreement with the results of our previous study on stoichiometry of VES and Fe(III) interaction. The present paper is the first mechanistic attempt to characterize and understand the nature of a VES-based system interaction with Fe(III) by using a model compound that has the same headgroup as tested VES. The findings of the present study can be utilized to further investigations of the effects of additives on the performance of VES- based systems.

Steam flooding is the most widely used thermal enhance oil recovery (EOR) process to recover bitumen and heavy oil. This process has been proven to be reliable, thus, establishing itself as a favorite among other thermal EORs. However, the excessive water usage to generate steam causes environmental concerns such as air and water pollution. Thus, a noble idea to reduce the sole dependency on steam alone is to co-inject solvent with steam. Solvent will aid the oil recovery process by improving miscibility aside from the oil displacement mechanisms from steam itself. Three core flooding experiments were conducted on a heavy oil sample from Texas; namely, steam flooding (E1), CO 2 -steam flooding (E2), and CO 2 - MS- steam flooding (E3). MS is a corn based environmentally friendly solvent which is tested for the first time for heavy oil extraction via solvent-steam injection process. Because CO 2 is known as asphaltene insoluble solvent, asphaltene precipitation was also investigated on spent rock samples to determine the formation damage occurring during the process. An ASTM method was used to determine the amount of asphaltenes in initial oil sample, on produced oil samples, and on residual oil samples. Another flow assurance problem is emulsion formation which occurs widely in any steam processes. Hence, the emulsions formed during solvent-steam and steam experiments and the role of asphaltenes on emulsion formation are investigated. It has been observed that CO 2 enhances the asphaltene precipitation and results in consolidation of core samples which reduced significantly the oil production. The use of asphaltene insoluble solvent CO 2 with an asphaltene soluble solvent (MS) enhanced the oil production, increased the sweep efficiency and decreased the water-in-oil formation. With this study for the first time asphaltene soluble and insoluble solvents co-injected together with steam to recover a heavy oil from Texas. We also analyzed the oil displacement mechanism through asphaltene precipitation and emulsion formation.

A systematic study of various temporary and permanent clay stabilizers was conducted with assorted binary blends of bentonite and silica flour. A specific stabilizer's performance is directly correlated to the type and loading of the inhibitor and particular ratio of existing inorganic substrate. Results exhibited high performance correlation; response surface general topography is dependent upon the temporary or permanent characteristics of the stabilizer. Studies comprised combined mixture, single numeric, optimal, design of experiment and performance test data gathering utilizing a low-pressure fluid loss cell. A predetermined concentration of unadulterated sodium bentonite and 325-mesh silica flour were blended into water at a specific RPM and duration in the presence of a particular stabilizer then placed into a the cell, sealed, and pressure was applied. Increased Darcy leak off slope values are reliable, accurate indicators of increased stabilizer performance thus each slope was calculated and plotted versus stabilizer dosage and inorganic substrate ratio. KCl was studied from 0 to 8 weight percent and used as a comparative guide for all stabilizers tested with the balance tested in their "as is" state from 0.0 to 2.0 gallons per thousand gallons. Temporary stabilizers typically provided a consistent topography with respect to performance, with a 20/80 bentonite/ silica flour ratio yielding the highest performance. Bimodal maximum performance inorganic ratios were present for permanent stabilizers tested. KCl dosage offset lab results correlate well with reported field application results. At higher stabilizer loadings superior performance relative to KCl was evident. Traditionally clay stabilizer selection is based upon Capillary Suction Time and Roller Oven testing methods. This alternate bentonite and silica flour comprehensive matrix clay stabilizer selection method is consistent, continuous, portable, field friendly and applicable over a wide range of stabilizer and variable inorganic matrix types.

Experimental observations regarding the formation of oil-water emulsions stabilized by nanoparticles and surfactants during oil production operations are presented. Similarities and differences between the two types of emulsions are discussed based on acquired separation profiles, as well as respective fluid interfacial properties. A state-of-the-art, portable Dispersion Characterization Rig (P- DCR) is used to run the experiments and a surveillance camera is deployed to monitor emulsion separation kinetics. Commercial grade mineral oil and distilled water are used as the test fluids. Silica nanoparticles of different wettability and surfactants with different HLB values are deployed to investigate commonalities/differences between surfactant and nanoparticle stabilized emulsions. Separation profiles were analyzed and similar behavior between the corresponding surfactant and nanoparticle emulsions was observed for the 25% water-cut case. For higher water-cuts, however, the surfactant stabilized emulsions were tighter than their nanoparticle counterparts, displaying much lower separation rates. In the most severe cases, the surfactants totally inhibited the oil creaming process and oil remained trapped in the emulsion for several hours. Multiple emulsions (O/W/O) were observed in certain cases (for hydrophilic nanoparticles and lipophilic surfactants (Span 80)). It appears, based on the aforementioned experimental observations, that the presence of surfactants can cause more severe problems to the oil-water separation process than the presence of an equal concentration of nanoparticles. Pendant drop measurements indicate that the surfactants can lower the interfacial tension between oil and water significantly, whereas the nanoparticles do not have a similar effect. Current research sets the basis for more thorough investigations aimed at providing guidelines for more efficient operation of separators handling surfactant or nanoparticle stabilized emulsions and better understanding of related phenomena.

The objective of this paper is to enhance the produced oil quality during solvent-steam flooding processes by using asphaltenes precipitants and environmentally friendly solvents as injection fluid. This way, it is aimed to increase the asphaltene deposition tendency and decrease the emulsion formation severity. Eight one-dimensional core flood experiments were conducted; one steam flooding, three solvent flooding, and four solvent-steam flooding. Five different solvents were tested; propane, n-hexane, toluene, Benzoyl peroxide (BP), and a plant-based environmentally friendly solvent (MS). Solvent and water injection, oil and water production, and temperature along the core flood were continuously measured during each experiment. Both produced oil and residual oil samples were further analyzed to investigate the quality of produced oil samples and the amount of asphaltenes deposited on spent rock. An ASTM method which uses n-pentane was implemented to separate asphaltenes from both produced and residual oil samples. The water content of produced and residual oil samples was determined through thermogravimetric analysis (TGA) and the water-in-oil emulsion content of produced oil samples was visualized with an optical microscope. To understand the impact of each SARA (Saturates, Aromatics, Resins, and Asphaltenes) fractions on produced oil quality during solvent-steam processes, every fraction was exposed to liquid or vapor water and examined under a microscope. It has been observed that stability of asphaltenes and emulsions varies in the presence of vapor or liquid water. Aromatics and Resins fractions are the main contributors of water-in-oil emulsion formation, and emulsion formation is enhanced with the addition of asphaltenes. Vapor-water (steam) promotes the formation of more severe emulsions than liquid-water. Hence, the emulsion formation mechanism was predicted to start with a foam-formation step in where the vapor steam diffuses into the liquid crude before condensing to form liquid water droplets, and then, forming an emulsion at lower temperatures. Since asphaltenes insoluble solvents were used, diffusion of steam occurs mostly in deasphalted oil and mainly in aromatics and resins.

In successful hydraulic fracturing operations, fracturing fluids should possess sufficient viscosity in order to transmit high pumping pressure downhole. This pressure creates fractures in formation and transports proppants that help to keep the fractures open after treatment. Fluid viscosity may drop when polymers in fracturing fluids suffer degradation due to, for example, oxidative species, especially in wells with elevated bottomhole temperatures. Fluid stabilizers are often needed in fracturing fluids to mitigate this effect. Commonly used fluid stabilizers in oil field operations are thiosulfate oxygen scavengers, such as sodium thiosulfate. Thiosulfate can quickly neutralize oxidative molecules, thus protecting polymers from being decomposed and extending the lifetime of fracturing fluids. Thiosulfate, however, may react to release hydrogen sulfide, especially at elevated temperatures. Hydrogen sulfide is poisonous to human and can also damage oil field assets by corrosion and scaling. To minimize hydrogen sulfide release, a series of lab tests were conducted to study hydrogen sulfide generation in high-temperature fracturing fluids. Extensive lab tests suggested that the hydrogen sulfide generation in fracturing fluids could be influenced by factors including test temperature, oxygen scavenger concentration, fracturing fluid formula, etc. At test temperatures of 350°F or below, the hydrogen sulfide generated was well below 10ppm. Without cooldown, most fracturing fluids prepared with crosslinked polysaccharides are limited to downhole temperatures up to 350°F. It is therefore less risky to use thiosulfate in these fluids without much concern for generating hydrogen sulfide. We observed that the dosage of thiosulfate influenced the outcome of the hydrogen sulfide generated at elevated temperatures above 350°F. Usually the more thiosulfate was added, the more hydrogen sulfide was produced. Without using excessive dosage of thiosulfate, the hydrogen sulfide generated, for example, could be less than 10ppm even at about 375°F or higher. With optimized selection of the fluid compositions, the amount of hydrogen sulfide produced could therefore be reduced significantly. The illustrative experiments include the search for safe boundaries of fracturing fluids used at high temperatures without producing hydrogen sulfide over regulatory permissible exposure limit. Guidelines on how to mitigate hydrogen sulfide generation will be recommended based on lab results.

Scale deposition is a common problem during oil production resulting in equipment corrosion, wellbore plugging, and production rate reduction. In unconventional reservoirs, the negative effect of scale formation and deposition becomes more pronounced as it severely damages the conductivity of hydraulic fractures. However, how and to what extent the scaling changes the gas production is unclear. In this work, a robust and integrated tool is developed to model scale deposition under dynamic flow conditions in unconventional reservoirs considering the damages to fracture and shale matrix. In doing so, a comprehensive compositional reservoir simulator (UTCOMP) coupled with IPhreeqc is utilized to predict carbonate and sulfate scales formation in the Marcellus shale formations. This integrated approach allows to adequately resolve the multiphase flow in the fracture network and near-wellbore region and to determine the associated geochemical behavior. Our results show that scale formation mainly results from changes in the physicochemical properties of brine (pH, temperature, and pressure) and/or mixing with incompatible brine compositions (e.g. mixing of fracturing fluid and formation brine). Precipitations of barite and calcite due to the incompatibility of fracturing fluid with formation water was identified to be the main cause of hydraulic fracture plugging, which resulted in fracture conductivity reduction. Based on the fracturing fluid composition and its invasion depth, fracture conductivity can decrease up to 10%. Due to the complex flowback of the fracturing fluid, we observed a time-dependent fracture plugging. Specifically, a moderate plugging of the fracture face occurs early in Marcellus formation causing a reduction in production peak rate while the fracture tip is severely plugged at later times and further reduces the gas production rate.

Despite the myriad of published literature on asphaltene, true understanding of its characterization, and deposition is still lacking. There have been many proposed models based on principles in thermodynamics, hydrodynamics, and many empirical equations proposed, however, further work still needs to be done to have a better grasp of the asphaltene deposition. In this study, we examine an integrated approach to evaluate asphaletene deposition in both the reservoir and wellbore as a function of fluid velocity. We discuss the effect of permeability reduction as a function of combined effects of surface deposition and interconnectivity loss due to pore blockage in the reservoir. The effects of pore surface deposition and pore blockage are evaluated based on published experimental data on sandstone and carbonate rock samples. Next, based on different wellbore/tubing configurations (uniform and tapered) and fluid types, the asphlatene deposition is evaluated within the wellbore considering both favorable and non-favorable regions. Simulated values obtained from OLGA TM are used to define these regions and critical particle sizes where there is a shift from Region I to Region II. Results indicate that in terms of asphaletene deposition in the reservoir, for sandstone samples, both surface deposition and pore throat plugging seem to contribute fairly equally to permeability reduction. In the case of carbonate however, pore blockage seems to be mainly dominant, which results in an almost instantaneous sharp decrease in sample permeability. Moreover, increasing fluid velocity, positively contributes to diminishing permeability reduction in sandstone samples, whereas it has no effect in case of carbonate samples. In case of deposition in the wellbore, asphaltene deposition rate is inversely related to fluid velocity in Region I whereas in Region II, it is directly proportional. More importantly however, this study determines particle size cutoff values for the two regions and does a systematic study of the impact that uniform and tapered wellbore configurations have on asphaltene deposition. Results of this study may change the industry's predictions of asphaltene deposition in both reservoir and wellbore. Improved understanding of asphaletene deposition leads to better production and far more accurate economic predictions.

Microwave heating has great potential to recover heavy oil reservoirs, because it significantly reduces the heating time and consequently the cost of heavy oil extraction. Moreover, heavy crude oils contain high amounts of polar molecules (asphaltenes) and polar functional groups, making them great microwaving candidates. This study investigates the microwave effectiveness for a specific heavy oil reservoir focused on its polar components. Furthermore, the impact of asphaltene precipitants and dispersants on microwave efficiency was investigated. A crude oil sample from Canada was subjected to microwave experiments for 30 seconds. Dielectric properties of the crude oil before and after exposure to microwave were mostly measured by using a vector network analyzer to quantify the overall polarity changes in the bulk crude. The impact of asphaltene precipitants (nC5 and nC7) and a dispersant (toluene) on microwave efficiency was also investigated. The crude oil sample was blended with nC5, nC7, or toluene at three varying doses (10%, 20%, or 50%) to investigate the impact of solvent dose on microwave efficiency. Microwave absorption and penetration depth were calculated to quantify the effectiveness of microwave heating. It has been observed through dielectric property measurements that microwave energy was absorbed by mainly the asphaltenes. Dielectric constant and loss tangent values of the blends prepared with asphaltene precipitants (nC5 and nC7) and toluene were measured before and after exposure to microwave to quantify the microwave absorption in different blends. Although precipitant mixtures had higher dielectric constants, the dispersant mixtures had much higher microwave absorption due to higher loss tangents. This finding was further supported by penetration depth measurements, in which dispersant mixtures had lower values, which led to higher microwave absorption of the crude oil mixtures. Microwave heating as a thermal enhanced oil recovery method is promising, however, complicated due to the uncontrollable nature of microwave penetration and absorption. This study reveals that while injection of an asphaltene precipitant to the desired reservoir locations can enhance the microwave penetration, injection of asphaltene dispersants will increase the microwave absorption. Cyclic injection of asphaltenes dispersants and precipitants may achieve the creation of effective heating spots within the reservoir by using only one microwave source.

The precipitation of a black, hard scale initially described as coked asphaltene began to occur in a heavy oil reservoir in Bakersfield, CA. The material had never been encountered before, and previously developed analytical techniques were not providing hard answers as to the composition of the materials. Traditional chemistries applied to remediate asphaltic materials were completely ineffective, as were mineral and organic based acids. The initial samples gathered were somewhat soluble in traditional asphaltene dispersants, and initial applications of those products did yield some favorable results, but only for a short period of time. Several of the wells failed due to the same precipitates as before which seemed to get more tenacious with each subsequent failure. As more wells began to present with this material, it was apparent that the material being observed was not something previously found in the San Joaquin Valley (SJV). Analysis using X- ray diffraction (XRD) and X-ray fluorescence (XRF) yielded results that indicated that the material was primarily organic even though the deposits gathered indicated a very hard scale. Carbon, Hydrogen, and Nitrogen (C,H,N) analysis also provided data inconsistent with the known precipitates in the SJV. Wet Analysis techniques were altered to investigate synergies between chemical types and additional laboratory analysis were conducted to identify the Total Acid Number (TAN) and Specific Carboxylic Acid Number (SCAN™) of the produced fluids. The laboratory and analytical testing was able to establish several key findings. First of all, the TAN and SCAN data for the affected wells concluded that the material being precipitated was low molecular weight Calcium Naphthenate scale. The wet analysis in the laboratory identified combinations of treatment products that were effective at solubilizing the material. This was an important find because those same products applied as stand-alone treatments were not effective at solubilizing the material, but when combined; were able to return the material to solution. The ongoing investigations also determined thatthe material became more insoluble with aging, indicating that a prompt response to the occurrence could make the difference in a successful chemical application. This paper provides an important awareness of previously unknown deposits that may occur in producing wells that may not be common to many areas domestically as most of the work published on the subject is from the North Sea, Norway, Great Britain, Western Australia, Bohai Bay, offshore Trinidad, Lousiana, the Gulf of Mexico, China, and Africa ( Baugh et al. 2005 ; Runham & Smith 2009 ; Shepherd et al. 2006 ; Turner & Smith 2005 ; Vindstad et al. 2003 ).

Asphaltene precipitation becomes a serious problem especially when it causes plugging of the formation, wellbore, or production facilities, which will significantly affect the productivity and final recovery of the area. This paper presents an overview of asphaltene properties, structure, and its impact on oil production operations. It also specifically, discusses different available modeling approaches used to analyze and predict asphaltene precipitation, flocculation, and deposition in oil reservoirs. We will review asphaltene in crude oil systems: asphaltene properties and their impact on oil production, including the effects of pressure, temperature, and composition.

Paraffin and asphaltenes deposits, scale deposits and emulsions formed by fluids incompatibility in oil-producing wells, and other formation damage mechanisms are a major cause of loss of well productivity. Organic and inorganic deposits can occur on the surfaces of well tubing and within the pores of the near-wellbore formation, reducing of flow efficiency and possibly blocking the flow paths completely. The damaging process may occur naturally during the production phase of the well or it can be triggered during wellbore intervention treatments or even during the wellbore construction stage. In general, formation damage is driven by more than one mechanism. A thorough assessment and diagnosis of the fundamental cause(s) of the formation damage is important to properly select the best remediation treatment and procedure. Even if there is no standard, best practices and methodologies to diagnose the cause(s) of the formation damage and evaluate potential chemical treatments have been developed. A discussion of the improved methods of problem identification, programs to remediate these problems, and stimulation software will be described in this paper. A synopsis of the potential causes that generate organic and inorganic deposits in the wellbore, diagnosis of formation damage, chemical treatment selection and applications are also discussed. Laboratory test evaluations and smart selection of chemical treatment, according to the type of formation damage, are presented, along with number of example case histories. Diagnosis of organic and inorganic formation damage, problem identification using production history data, reservoir and fluid properties, well configuration, and history of well intervention and/or stimulation that allowed tailoring customized formulation proved that this approach resulted in better wellbore cleanup and production increase.

This literature review summarizes the theory and application of chelating agents in scale removal. The objective of this work is to give the reader a better understanding of scale removal methods by chelating agents in oil field applications. This paper reviews results that were obtained through various laboratory tests, which aid in understanding chelating agent interactions with formation rock and formation fluids. Results were obtained through a variety of tests including compatibility, dissolution, Inductively Coupled Plasma (ICP), Environmental Scanning Electron Microscope (ESEM) and X-Ray Diffraction (XRD). At high temperatures, conventional acids such as hydrochloric acid (HCl) show severe corrosion, lack of penetration and sludging characteristics. Several organic acids were proposed to solve these issues. However, even organic acids result in solubility and incompatibility issues. Based on these shortcomings, chelating agents are often used and show good dissolving power, low corrosion, low sludging tendencies, excellent iron control, and some are highly degradable and environmentally friendly. In addition, chelating agents are commonly used to dissolve most oil field scales that are both insoluble in HCl and detrimental to production. This work summarizes the applications of chelating agents in the stimulation sector, including the latest developments and field applications of chelating agents. Readers can easily expand on this paper to further explore the wide range of applications chelating agents can offer the oil and gas industry.