Summary Problems related to crystallization and deposition of paraffin waxes during production and transportation of crude oil cause losses of billions of dollars yearly to petroleum industry. The goal of this paper is to present the knowledge on such problems in a systematic and comprehensive form. The fundamental aspects of these problems are defined, and characterizatin of paraffins and their solubility tendencies have been discussed. It has been established conclusively that n-paraffins are predominantly responsible for this problem. Comprehensive discussion on the mechanism of crystallization of paraffins has been included. Compounds other than n-paraffins, especially asphaltenes and resins, have profound effects on solubility of n-paraffins. In evaluations of the wax potential of a crude, the climate of the area concerned should be considered. Under the most favorable conditions, n-paraffins form clearly defined orthorhombic crystals, but unfavorable conditions and the presence of impurities lead to hexagonal and/or amorphous crystallization. The gelation characteristics are also affected the same way. An attempt was made to classify the paraffin problems into those resulting from high pipeline pressure, high restarting pressure, and deposition on pipe surfaces. Fundamental aspects and mechanism of these dimensions are described. Wax deposition depends on flow rate, the temperature differential between crude and pipe surface, the cooling rate, and surface properties. Finally, methods available in the literature for predicting these problems and evaluating their mitigatory techniques are reviewed. The available methods present a very diversified picture; hence, using them to evaluate these problems becomes taxing. A top priority is standardizing these methods for the benefit of the industry. Introduction Problems related to crystallization and deposition of paraffin waxes during production and transportation of crude oil are well known. Extensive research by many workers has enriched our knowledge on the subject. Paraffin problems are causing losses of billions of dollars per year to petroleum industry worldwide through the cost of chemicals, reduced production, well shut-in, less utilization of capacity, chocking of the flowlines, equipment failure, extra horsepower requirement, and increased manpower attention. Indepth understanding of such problems is of paramount importance to oilfield operators in their search for technical/economic solutions. This paper reviews the fundamentals of these problems; the mechanisms of wax crystallization, gelation, and deposition; and laboratory methods for predicting and quantifying these problems. Characterization of Paraffin Wax By historical definition of the problem, the organic compounds of the crude, called paraffin, must be insoluble in the crude at the producing conditions.1 They must be higher-molecular-weight compounds of various homologous series. The classes of compounds recognized as possibly being in the deposits are (1) aliphatic hydrocarbons (both straight and branched chain), (2) aromatic hydrocarbons, (3) naphthenes, and (4) resins and asphaltenes. Gruse and Stevens2 described some representatives of each of these classes of chemicals, their structures, and their boiling and melting points. In reality, however, these compounds can be present in crude oil in pure generic forms or mixture of these forms. For example, in a given compound, alicyclic and aromatic rings can coexist in a streight, chain moiety. The length and number of side chains and the presence of alicyclic, aromatic, and condensed rings have a profound effect on melting point, boiling point, and solubility of these compounds in crude oil. Recognized as the principal constituents of macrocrystalline waxes, n-paraffins give rise to clearly defined, needle-shaped crystals. The branched-chain paraffins make up the major portion of microcrystalline waxes. The long, straight-chain naphthenic and aromatic paraffins also contribute to microcrystalline waxes and have a marked effect on the type of crystal growth of macrocrystalline waxes.1 Macrocrystalline waxes lead to paraffin problems in production and transportation; microcrystalline waxes contribute most to the tank bottom sludges. It has been established conclusively that wax deposited during production and transportation of crude oil predominantly consists of n-paraffins with smaller amounts of branched-chain and cyclic paraffins and aromatics.3 In a typical example, analysis of oil well equipment deposits showed that paraffins are the dominant species (52%)besides asphaltenes and resins (<5%)4; the balance is made up of crude oil, water, and mechanical impurities. Paraffin wax molecules are straight-chain alkanes that contain more than 15 carbon atoms and have very little branching. Swetgoff5 listed the melting points of some paraffin molecules. Waxes containing up to C80 paraffin compounds have been reported.6 Paraffin compounds containing more than 20 carbon atoms are considered potential troublemakers for oilfield operators. Studies by Holder and Winkler7 showed that wax that came out of heavy fuel oil on cooling from 9 to -10°F had a composition centering on C20 and a spread from C16 to C27. As the temperature increases, the average number of carbon atoms of the crystallized wax in creases. For example, wax composition centered on C22 when the same oil was cooled between 33 and 9°F with a spread of C17 to C29. Leonidov et al.8 demonstrated that the average carbon numbers of waxes precipitated at 14, 32, 68, and 86°F were 22, 23, 26, and 29 respectively. While evaluating wax problem potentials of a given crude. we must consider the following points:the concentration of n-paraffins;their carbon number distribution;the concentration of branched paraffins, naphthenes, and aromatics;the concentration of resins and asphaltenes; andthe climate of the area or the temperature regimes. While the first, second, and fifth factors would help us predict the paraffin (macrocrystalline) wax deposition potential, the others would indicate moderation in the extent of problem.

Asphaltene deposition is a long-standing problem that threatens the uninterrupted production of crude oil. Unlike other flow assurance problems, downhole asphaltene deposition is not well-understood partly as a result of the complexity and diversity of the asphaltene chemical structure. Continuous downhole asphaltene inhibitor injection is one of the preventive strategies used to mitigate the asphaltene deposition problem. Such chemicals that are injected in low dosage are screened in the laboratory before field implementation. Over the last 20 years, various asphaltene testing methods have been proposed for product selection and research and development. Still, the lack of lab to field correlation remains a challenge for the operators, service providers, and chemical companies. Therefore, the search for robust, rapid, and reproducible lab screening methods for asphaltene inhibitors is ongoing. This review summarizes lab evaluation techniques adopted by different researchers, their governing principles, and the pros and cons. It may serve as a guide for adopting appropriate strategies and pursuing further investigations on the lessons learned. The hope is that, with a more in-depth understanding of the current methodologies, a better workflow can be designed to select the proper asphaltene control products for field implementation.

The term mixed scale pertains to the scales found in oil and gas production system containing both organic and inorganic constituents in such a way that either aqueous-based inorganic dissolver or solvent-based organic dissolver fails to act on it. These scales are also known as wetted scales. This research discovers formulations which can effectively dissolve and disperse mixed scales dominated by inorganic content. Micro-emulsion-based solutions are identified as the best in tackling such mixed scales. A few inorganic and organic dissolving chemicals along with surfactants and co-surfactants are considered in this research to develop environment friendly solutions. The stable micro-emulsions are subjected to detailed dissolution study to establish their efficacy. The synthesized chemical solutions are shown to dissolve mixed scales of different composition. A chelant-based micro-emulsion formulation is also found to be effective in dissolving difficult to treat metal naphthenate scales co-precipitated with organic content, which is a novel application.

Recently observed production behavior in a maturing carbonate oil reservoir indicated that many production strings were getting plugged with solid scales, requiring tubing clean-out jobs. This is the main reservoir of a supergiant onshore carbonate oil field operated by ADCO since 1973. Some cases proved to be no more than calcium carbonate scaling following water breakthrough and the tubing blockage was successfully treated with acid washing. A number of plugged strings revealed that a non-mineral hard scale was the cause of the blockage. Upon analysis, such scales proved to have an organic composition rich in asphaltenes. While solvent washing was successful in removing the blockage, rapid reoccurrence was observed in many cases. The subsurface asset team embarked on a detailed reservoir monitoring and fluid compatibility study to establish causative factors. One of the aims of the study was to check a possible link between the asphaltenes deposition with a naturally occurring tarmat and a rich-gas injection pilot, both located in the severely affected part of the reservoir. This work revealed that although the severity of the problem is higher in the tarmat area, asphaltenes mobilization from the tarmat layer was not considered a realistic mechanism. Although PVT studies revealed that rich gas dissolution in the crude at reservoir conditions triggered asphaltenes instability and precipitation but occurrence of asphaltenes deposition in the field seemed unrelated to the rich-gas injection as the injected gas was moving in a different reservoir subzone. Most of the plugged strings were unlikely to have had gas breakthrough at the time of problem detection and no clear spatial relationship could be evidenced. A preferred explanation may be that asphaltenes precipitation is related to differences in crude oil composition within the studied reservoir. The reservoir might have seen successive oil influxes from two source rocks with wide distribution of mixing ratios. Asphaltenes originating from one of the source rocks might cause greater fluid instability even at the observed low concentrations. Production rate sensitivities indicated that asphaltenes blockage was retarded at higher production rates. Many asphaltenes dispersant/inhibitor chemicals were evaluated for effective tubing clean-out and preventing asphaltenes deposition. Some chemicals proved to be more effective in mitigation and prevention of asphaltenes deposition.

Two of the prominent on-shore fields in Abu Dhabi are facing asphaltene deposition in a number of their oil producing wells. Several studies were carried out to understand the reasons for asphaltene unstability in the crude in both fields to help develop the appropriate mitigation strategies. A summary of the findings will be presented in this paper, however, the focus will be on the efforts undertaken to improve the current asphaltene clean-out formulations that are being used in the field. These formulations are composed of a dispersant chemical mixed with diesel as a solvent in 20:80 ratio and are pumped with the use of a Coil Tubing Unit (CTU) in tandem with jet blaster. However, the success rate reported for such clean-up jobs was 40% on average. Hence lab testing was carried out on a number of new dispersants and other potential solvents to improve the efficiency of the clean-up operations. After testing a combination of 8 commercially available dispersants with 3 solvents: Diesel, light gasoline oil (LGO), heavy aromatic naphtha (HAN), it was clear that a mixture of HAN with 3 particular dispersants in a 90:10 ratio were many times more efficient than the currently used formulations. These top lab ranked formulations were then field trialed in 7 wells by bullheading only, soaking overnight and running a gauge cutter to prove accessibility and success of the clean-up job. The wells were found to be perfectly cleaned with 25% reduction in the chemical requirement and a major saving in terms of avoiding the use of CTU for the clean-up operation. Implementation of new formulations would affect multimillion dollar cost saving. The savings increase many fold when opportunity costs against the previous unsuccessful jobs is taken into account. Besides, valuable resources like CTU can be gainfully deployed elsewhere. Results of this field trial will have larger implications for ADCO in the future as the number for asphaltene affected wells is rising as a result of field maturity and implementation of Enhanced Oil Recovery (EOR) and Artificial Lift (AL).