As offshore activities continue to progress into deepwater, ensuring the well stream flow from downhole to process facilities is becoming a critical issue for development of the reservoirs. Flow assurance is the technology and ability to transport hydrocarbon fluids from reservoir to export point, econom-ically, over the life of a field, and in all kinds of environment. Flow assurance addresses broad aspects of the problems and solutions of flow distortion, including solid depositions of waxes, hydrates, paraffins, asphaltenes, and scales from reservoir to topsides.
When physical conditions are "wrong," hydrates form, or waxes and asphaltenes come out of the well stream fluids, plugging up flowlines and processing equipment. Cleaning of a plugged flowline/pipeline is often very costly, time consuming, and technically challenging. Production has to be interrupted and may sometimes require a complete shutdown. Maintenance and repair methods get more complicated and expensive as the water depth increases. Procedures for intervention also need to be pre-considered because these procedures may influence the overall system design including Christmas trees and flowlines.
Hydrates are solidified, metastable compounds. Their properties and stability depend on physical conditions like pressure and temperature. The ice-like compounds of gas hydrates crystallize from the lighter hydrocarbons (and hydrogen sulfide and other gases), free water, and a seed (scale/silt, etc.).
Low temperature, high pressure, and gas at or below the water dew point in the presence of free water, promote formation of hydrates. The duration of hydrate formation can range from instantaneous to a few hours. As long as free water is present, hydrate formation can take place in a gas stream (methane, carbon dioxide, hydrogen sulfide), in a live oil stream, or in multi-phase flow.
As a solid organic phase, mainly long-chain n-alkanes (C16-C80+), wax comprises a mixture of components. In oils, wax crystallizes within the fluid as the fluid temperature drops to below the cloud point. However, it only deposits on the pipe wall when the wall temperature is below the cloud point and colder than the bulk fluid. The wax crystallization process develops in three stages:
- Nucleation, at which the first nuclei appear
- Growth, at which mass is transported from the solution toward the nuclei
- Agglomeration, at which the developed crystals join together and bigger crystals are formed.
Wax precipitation can occur in the reservoirs, the production column, the flowlines, and in the surface production equipment.
Cloud point/pour point
Cloud point is the temperature at which paraffin wax begins to crystallize and is identified by the onset of turbidity as the temperature is lowered. In other words, cloud point is the highest temperature at which the wax crystal forms. The cloud point of a particular crude is dependent on the oil composition and is affected by small amounts of high molecular weight paraffin in the crude. As the temperature falls below the cloud point, wax crystals begin to precipitate from the oil phase.
Pour point is the lowest temperature at which the liquid is observed to flow when heated under prescribed conditions. Therefore, the crystals of waxes or paraffins start to liquefy as their temperature reaches the pour point.
Wax deposition is controlled by many factors besides the fluid properties. The key controlling factors are the temperature difference between fluid and pipe wall (thus the heat flux), the concentration gradient, and the mass transfer resistance determined by fluid properties and flowrate, etc.
Pressure has different effects on the wax formation in single phase system and multiphase system. In a single-phase oil system, since the wax phase is denser than the oil, an increase in pressure slightly increases the wax deposition tendency. In a multiphase system, an increase in pressure drives the light ends of the mixture into the liquid phase and tends to decrease the cloud point, therefore, tending to reduce the amount of wax formed at a particular temperature.
Paraffin precipitation is normally associated with changes in the physical environment surrounding the crude oil. Due to the normal subsurface temperature gradient, and the hydrostatic pressure variation in crude oil, when the oil is produced up the tubing, a pressure and temperature change occurs. This allows the lighter hydrocarbons to break out of solution and become a gas phase. These lighter hydrocarbons help keep the heavy end paraffins in solution. Sudden pressure drops may also promote precipitation.
While hydrate formation and paraffin precipitation are direct results of physical (temperature and pressure) changes, asphaltene deposition is more affected by chemical changes in the crude. Asphaltenes do not dissolve in crude, but rather float as dispersed colloids. A change in pH (lowering), carbon dioxide, injection, and/or introduction of non-aromatic solvents strips away the "outer part," which supports the dispersion of the asphaltenes in the crude. Without the outer part, the asphaltene molecules will flocculate and precipitate. After precipitation of asphaltenes, the remaining parts of the crude are malthenes.
Control
Generally, there are three basic methods of controlling hydrates, waxes, and asphaltenes: thermal, chemical, and mechanical. They may be used alone or in combination. Thermal methods encompass heat conservation using a passive insulation system, an active addition of heat, or an active system of insulation and heating. The active heating can be fluid heating, electric heating, or thermal-chemical exothermal heating.
Chemical methods include both inhibition and dehydration for hydrate prevention and the use of long chain polymers to maintain waxes and asphaltenes in the fluid.
Mechanical means, such as pigs, may be used for "prevention" if operated on a planned frequency. Another mechanical tool is coiled tubing.
There are three ways currently in use to combat the formation of hy-drates:
- Preservation and application of heat by using insulation and supplemental heating
- Use of inhibitors
- Dehydration or removal of enough water from the stream so that a hydrate will not form (glycols).
Inhibition of the hydrate formation process is a commonly used practice. There are two kinds of inhibition - thermodynamic and kinetic. Thermo-dynamic inhibition prevents hydrate formation by adding a third active component into a two-component/ intermolecular interaction and thermodynamic equilibrium between molecules of water and gas, and to modify the hydrate formation temperature.
Kinetic inhibitors are adsorbed on the surface of hydrate micro crystals, and micro dispersed droplets of water are absorbed in the flow of a fluid. Unlike thermodynamic inhibitors, kinetic inhibitors do not lower the hydrate formation temperature, but preclude the process of hydrate formation. Kinetic inhibition is a temporary inhib- ition and is effective in producing and transporting hydrocarbons.
Glycol dehydration may be more efficient, but requires expensive downstream process (recovery) facilities. Triethylene glycol has been used by Shell to dehydrate produced gas in the Mensa flow lines. In the future, subset separation may become a viable means of water removal.
As a tool for removing blockages, coiled tubing can be inserted through a lubricator at a platform or floating workover vessel to deliver inhibitors like glycol or methanol in to the face of the blockage.
Combating wax
Wax remedial treatments often involve the use of solvents, hot water, the combination of hot water and surfactants, or hot oil treatments to revitalize prod-uction. Eight methods are available for removal of wax, paraffin, and asphaltenes: hot fluid, solvents, dispersants, crystal modifiers, a combination of the above; mechanical means (scraping), SNG (or NGS, nitrogen generating system) thermo-chemical cleaning, and microorganisms
There are chemicals available that can be tailored to work with a particular crude oil composition, but tests should be carried out on samples of the crude to be sure that the chemical additives would prevent the wax deposition.
Removal by means of a hot fluid works best for downhole and for short flowlines. The hydrocarbon deposits are heated above the pour point by hot oil, hot water, or steam circulated in the system. This practice, however, has a drawback. The use of hot oil treatments in wax-restricted wells can aggravate the problem in the long run, even though the immediate results appear fine.
The combined hot water and surfactant method allows the suspension of solids by the surfactant's bipolar interaction at the interface between the water and wax. An advantage of this method is that water has a higher specific heat than oil, and therefore usually arrives at the site of deposition with a higher temperature.
Solvent treatments of wax and asphaltene depositions are often the most successful remediation methods, but are also more costly. There-fore, solvent remediation methods are usually reserved for applications where hot oil or hot water methods have shown little success. When solvents contact the wax, the deposits are dissolved until the solvents are saturated. If they are not removed after saturation is reached, there is a strong possibility that the waxes will precipitate (re-crystallize), resulting in a situation more severe than that prior to treatment.
In the case of crystal modifiers (pour point depression)/dispersants, paraffin wax crystal modifiers are those chemically functionalized substances that range from polyacrylate esters of fatty alcohol to copolymers of ethylene and vinyl acetate. Their special structures, the portions of the backbone of the polymer or their pendent groups of these substances, can allow them to interact with the crystallizing waxes present in a crude oil mixture. Crystal modifiers attack the nucleating agents of the hydrocarbon deposit and break down and prevent the agglomeration of paraffin crystals by keeping the nucleating agents in solution.
Dispersants do not dissolve wax but disperse it in the oil or water through surfactant action. They divide the modifier polymer into smaller fractions that can mix more readily with the crude oil under low shear conditions.
NGS, introduced by Petrobras in 1992, is a thermo-chemical cleaning method. The basic concept of NGS is related to the irreversible fluidization process of the organic deposits. Such process is caused by the simultaneous actions of the temperature increase of the fluid and paraffin, the internal turbulence during the flow, and the incorporation of the organic solvent into the deposits.
The heat is generated with nitrogen simultaneously by the chemical reaction between two inorganic salts in aqueous saturated solution. The NGS process combines thermal, chemical, and mechanical effects by controlling nitrogen gas generation to comprise the reversible fluidity of wax/paraffin deposits.
Pigging is the oldest way of cleaning out a flowline - by mechanically scraping the inside of the line. Pipeline pigs travel the length of a pipeline driven by fluid. A variety of pigs, either soluble (gel pigs) or insoluble, are introduced into the flowline.
Many pig runs may be required to effectively clean the line. The effectiveness of the pigging operation can vary widely depending on the design of the pigs and other pigging parameters. Modular pigging loops for subsea manifolds have been developed. The pigs are launched from the platform through an auxiliary line to the subsea equipment. From there, they return to clean the main flowline.
Microbes are routinely used for oil spill remediation. Recently, in Venezuela and Alaska, microbes were successfully used to clean out wellbores. Based on the reported results of these tests, it is conceivable to assume that this method would be successful for paraffin removal from flowlines.
Deepwater production
The deepwater production environment is characterized by low seafloor ambient temperatures, high tubing head flowing pressures, and higher external hydrostatic pressure. The high external pressure has a direct impact on the mechanical design of the flowline/pipeline, while the low ambient temperature generally has a larger impact on the hydraulics of a flowline/ pipeline. Solid deposition can occur at steady and transient states and can build up into restrictions and blockages in the reservoirs, well bores, flowlines, risers and process facilities.
Flow assurance is a common issue in design consideration for almost all producing areas, both onshore and offshore. Flowlines and risers are often insulated, and chemical injection umbilicals are required. Pigging facilities should be incorporated for routine, as well as intervention pigging.
The industry has established solutions to prevent problems and remedial means to employ when problems occur. However, implementation of these well-known flow assurance measures carries unique challenges, with a major impact on capital expenditures and operating expenditures of deepwater oil and gas production. Accurate prediction of lifetime flow and fluid characteristics and the selection of flow distortion prevention and remediation methods are the key factors in deepwater field developments.
Some of the newest, most innovative techniques of flowline blockage prevention and remediation are used to remove hydrates, wax, and asphaltene formation today. This kind of blockage can lead to some serious problems in an onshore flowline, but remediation is possible. When these problems occur offshore, locating and unblocking the line becomes much more severe and causes costs to go up as the water depth increases.
Continuous efforts must be made to improve flow assurance techniques. New tools are currently being developed for unblocking flowlines in deepwater. As drilling activities move toward deepwater and ultra-deepwater regions, the recrudescence of a flow assurance problem is expected. As water depth increases, flow assurance becomes more essential to ensure efficient well stream flow.
References
Sloan, E., Offshore Hydrate Engineering Handbook, SPE Monograph Vol. 21, 2000.
Chin, Y. and Bomba, J., "Review of the State of Art of Pipeline Blockage Prevention and Remediation Methods," the Proceedings of 3rd Annual Deepwater Pipeline& Riser Technology Conference & Exhibition, 2000.
Author
Dr. Y. Doreen Chin is the manager of Flow Assurance of J P Kenny. Dr. Chin has a B.Sc. in Thermal Energy Engineering from North-China University of Energy, a Master degree in Thermo physics from Tianjin University, China, and a Ph. D in Mechanical Engineering from the University of Houston.
