The present invention relates to an improved method of transporting hydrocarbon crude oils containing paraffin wax, asphaltenes, or mixtures thereof, and compositions for use in such method. More particularly, the present invention relates to the introduction into low water hydrocarbon crude oils contaminated with paraffin wax, asphaltenes, or mixtures thereof, and which oils are normally susceptible to deposition by such contaminants, of an effective deposition inhibiting amount of an oil soluble organic compound having at least one oleophobic and hydrophobic fluoroaliphatic group. The present invention also relates to crude oil compositions contaminated with deposition susceptible paraffins, asphaltenes, or mixtures thereof, and containing an effective deposition inhibiting amount of such oleophobic and hydrophobic fluoroaliphatic group containing oil soluble organic compounds.
Crude oils are complex mixtures comprising hydrocarbons of widely varying molecular weights, i.e. from the very simple low molecular weight species including methane, propane, octane and the like to those complex structures whose molecular weights approach 100,000. In addition, sulfur, oxygen and nitrogen containing compounds may characteristically be present. Further, the hydrocarbyl constituents may comprise saturated and unsaturated aliphatic species and those having aromatic character.
By a variety of fractionation procedures crude oils can be separated into various classes, the most common of which is boiling range. The mixtures which are in the lower boiling ranges generally consist of materials of relatively simple structures. The mixtures which are in the high boiling point ranges comprise substances which, with the exception of paraffins, are so complex that broad terms are applied to them such as resins and asphaltenes. Resins are poorly characterized but are known to be highly aromatic in character and are generally thought to be high molecular weight polynuclear aromatic hydrocarbons which melt over a wide, elevated temperature range. Asphaltenes are even more complex chemically--some of which suffer thermal decomposition before melting. They are high molecular weight polymers in colloidal suspension. Resins and asphaltenes characteristically contain sulfur, nitrogen or oxygen-containing compounds. Paraffins are linear or branched chain hydrocarbons in the range of C.sub.18 H.sub.38 to C.sub.60 H.sub.122 and are usually waxy solids with widely varying melting points. Paraffins generally have limited, temperature-dependent, solubility in produced crude oils. This poor solubility creates a considerable problem for the oil producer.
The problem is aggravated by the very nature of oil production, as crude oil is generally removed from a high pressure or high temperature environment and then is subjected to atmospheric pressure and low temperatures.
The paraffin is usually soluble in crude petroleum under "down-hole" conditions. Ordinarily, as the petroleum is brought to the surface, its temperature is reduced and the crude is subjected to a diminished pressure. As the crude leaves the wellhead at the reduced pressure, dissolved gases, which act as natural solubilizers for paraffin, tend to come out of solution. These two factors, the decrease in temperature and the loss of dissolved gases, decrease the ability of the remaining crude to keep the paraffin solution. As a result, wax crystals may precipitate on any appropriate surface.
When the petroleum waxes precipitate, they cause a myriad of problems for the oil producer. The precipitated waxy solids can create flow restrictions by depositing or accumulating downhole on tubing, rods, and sub-surface pumps; and aboveground in valves, piping, separators, and storage tanks. These troublesome deposits are combinations of an array of molecular weight hydrocarbons and adsorbed impurities.
Since any given crude always contains a mixture of alkanes (saturated hydrocarbons) of different molecular weights, different solubilities and different melting points, the associated paraffin deposits will vary in content depending on the deposition conditions. The major influences on the quantity of the deposit, as well as its composition, are the bulk oil and pipe surface temperatures, the temperature gradient between the oil and surface, and the flow rate of the oil.
Important factors determining the amount and rate of deposition of wax include the pipe surface and bulk oil temperatures relative to the cloud point of the crude. The cloud point of a crude is generally defined as the temperature at which wax crystallization begins. If the temperature of both the pipe and the oil flowing through it are above the cloud point, little or no waxy deposition will occur. If, however, the temperature of the inside surface of the pipe falls below the cloud point of the oil and the bulk of the flowing crude oil is at a higher temperature, wax will characteristically be deposited on the pipe surface. If the pipe surface is only slightly cooler than the cloud point of the oil, and the oil is much warmer, a lesser amount of waxy deposit will form, generally composed of the highest molecular weights, highest melting, hardest waxes in the crude. If the pipe surface temperature is much lower than the bulk oil temperature, a greater quantity of softer, lower melting deposit will usually accumulate.
If the gradient is reversed and the pipe wall is warmer than the oil flowing past, little or no deposition will occur, even if the temperature of the pipe and the oil are both below the oil's cloud point.
The flow rate of a crude past a deposition surface may also influence the composition of the deposits. A high flow rate tends to selectively remove the lower melting, softer fractions from the growing deposit, resulting in the formation of a hard dense deposit of high melting wax. A very low flow rate allows the inclusion of low melting, softer waxes and even of oil fractions in the waxy deposits. The net deposit is generally a very soft, low melting deposit.
Because of the diverse conditions that exist in a production system, it is not uncommon for several of the conditions for deposition to be present in the same system. This can result in different types of deposits forming in different locations within the same system. Soft, low melting deposits may form downhole while hard, higher melting deposits may form downstream of a choke or a valve in the pipeline leaving the well.
There are many methods of handling paraffin deposition. These can be divided into 3 categories: mechanical, thermal, and chemical.
A widely used mechanical treatment involves running a scraper that mechanically cuts the deposit from the tubing. Wirelining the tubing and "pigging" the flowlines are two examples.
Thermal treatment normally consists of minimizing heat losses and the addition of external heat to the system. Insulation of flowlines and maintaining a higher pressure in the flow lines that minimizes cooling through dissolved gas expansion are two examples of minimizing heat losses. Procedures such as steaming the flowlines, installing bottomhole heaters, and circulation of hot oil or hot water are examples of the application of heat in an effort to melt or increase the solubility of the deposit.
Chemical control generally falls into one of two classes: (1) using a solvent to dissolve the deposit once it has formed and (2) inhibiting wax crystal growth or inhibiting its adherence to the tubing wall.
Solvents used for dissolving paraffin deposits generally have a high aromatic content. A variety of solvents, including relatively low wax crude oils, are heated when used to increase the wax solution capacity of the solvents. Unfortunately, this procedure can be prohibitively expensive, particularly where such solvents are not readily available.
Typical paraffin inhibitors include certain known copolymers capable of crystal distortion or modification during the wax deposition process. Because the use of such copolymers involve a cocrystallization mechanism, it is necessary to have the copolymer in solution above the cloud-point temperature of the crude. This cocrystallization mechanism prevents or interferes with the molecular diffusion mechanism of deposition, and is believed to modify the crystal structure of the precipitated waxes into small, highly branched structures with low cohesive properties. Three popular crystal modifiers are copolymers in these groups: (1) Group A--copolymers of ethylene vinyl acetate, (2) Group B--copolymers of C.sub.12 through C.sub.30 methacrylates, and (3) Group C--copolymers of olefin/maleic anhydride esters.
Products of this type are commercially available under the trade names Shellswim.RTM., Waxstock.RTM. and Marchon.RTM.. Some are described in U.S. Pat. No. 3,776,247 and British Pat. Nos. 1,161,188 and 1,154,966. However, not all waxy crudes are beneficially affected by treatment with such substances, possibly because the ability of any particular conventional popular copolymer to cocrystallize will vary depending on the particular crude oil treated.
Asphaltenes may also precipitate from crude oils, likewise creating a myriad of problems for the oil producer.
Asphaltenes are aromatic-base hydrocarbons of amorphous structure. They are present in crude oils in the form of colloidally dispersed particles. The central part of the asphaltene micelle generally consists of high molecular weight compounds surrounded and peptized by lower weight neutral resins and aromatic hydrocarbons.
Any action of chemical, electrical or mechanical nature that depeptizes the asphaltene micelle may lead to flocculation and precipitation of the asphaltenes from the crude oil. The addition of low-surface-tension liquids--i.e. below 24 mN/m [24 dyne/cm] at 25.degree. C., such as gasoline, pentane, hexane, petroleum naphtha, etc. may precipitate asphaltenes. The addition of HCl during acidizing also tends to cause the formation of precipitated asphalticacid sludges. The flow of crude oil through porous media may also result in the precipitation of asphaltenes because of the neutralization of their charge by the streaming potential.
Asphaltene deposits are characteristically hard, brittle, dark black, dry solids, similar in appearance to coal and other bitumens. These deposits are very difficult to remove from a system because typical thermal methods of hot oil or water treatment are generally totally ineffective. The deposition of these materials also constricts or blocks the passage of crude oil causing reduced efficiency of production. Prevention or removal can be attempted chemically through the use of aromatic solvents, solvent accelerators, or the resinous components of crudes. Here again, such procedures can be prohibitively expensive and may not be effective.
Other approaches that have been suggested to inhibit or prevent asphaltene and paraffin deposits include the use of aqueous surfactant solutions to form low viscosity oil-in-water emulsions as shown in U.S. Pat. Nos. 3,943,954, 4,265,264, 4,429,554 and 4,239,052. Such emulsions generally contain a rather high percentage of water, for example 10-40% water, which must be removed. Removal is not always easy and yields large volumes of water contaminated with oil. High treating temperatures are required for separation of the water and this results in additional expenditures. Also, corrosion problems, freezing problems, and emulsion inversion into highly viscous water-in-oil emulsions problems may be associated with such aqueous emulsions, depending upon the nature of the field conditions, local climate, and the like.
Inhibition of paraffin and asphaltene deposition by crude oils is achieved by the addition to such oils of an effective amount of paraffin and asphaltene deposition inhibitors which are oil soluble organic compounds having at least one oleophobic and hydrophobic fluoroaliphatic group.
USPTO Backgrounds
USPTO Backgrounds