The deposition of paraffin and asphaltene in oil wells are among the most common problems leading to the deterioration of oil and gas production; however, they are among the easiest to remedy with proper treatments. An increase in production of 10%, 30% or even 100% after proper treatment is not uncommon in wells having paraffin and asphaltene problems.

Some wells that have wax problems may also have a combination of other problems; thus paraffin treatments alone may not be sufficient to optimize production. Wells where paraffin problems are the primary reason for production deterioration have the best chance of production increase after treatments.

When increased production is possible, it is usually experienced after the removal of wax buildup that has been deposited in the formation (formation damage). The removal of those deposits precipitated in the formation restores permeability and again allows the free flow of petroleum. The removal of the deposits in the tubing, flow lines, storage tanks, etc. leads to increased efficiency, decreased operational cost and minimized down time.

There are several causes leading to the deposition of paraffin and asphaltene in the formation. Some of those causes occur naturally, others are induced by well specific production practices. Natural causes include streaming potential (due to the flow of the oil); and temperature drop at the face of the formation, due to the expansion of the fluids as they enter the well bore. Deposition induced by the production practices include temporary vacuum pumping (attempting to pump more than the well’s capacity), injection of cool fluids (chemicals, acid, etc.) some solvent treatments, and most hot oil treatments.

Any organic deposit (heavy hydrocarbon deposit) associated with production is often called paraffin or wax. While paraffin compounds are usually the major component in these deposits, they are frequently a mixture of paraffins and asphaltenes. Their deposition in the formation, tubing, flow lines and other production facilities leads to a decrease in production and an increase in operational problems.

Crude oil quality differs even between two wells producing in the same field from the same reservoir. Therefore, crude oil paraffin and asphaltene content and its impact on production is well specific. Furthermore, Paraffin deposits, in addition to containing asphaltenes, may contain resins, gums, salt crystals, scales, clays, silts, sand and water.

Paraffins are straight or branched chain non-polar alkanes of relatively high molecular weight. Their chains usually consist of 20 to 60 carbon atoms with a melting range of 36 - 102°C (98 - 215°F). Asphaltenes, on the other hand, are high molecular weight cyclic aromatic compounds which usually contain nitrogen, oxygen and/or sulfur in their molecular structure. Their melting range is higher than that of paraffins. Asphaltenes are usually negatively charged polar compounds.

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.

The presence of paraffin and asphaltene in the crude oil does not lead to problems in production or operations. It is their precipitation that leads to those problems. The precipitation and deposits of paraffins and asphaltenes are generally caused by a change in equilibrium conditions surrounding the produced petroleum, i.e., pressure, temperature, flow rates and/or electrostatic effects.

Deposition in the Formation

Streaming Potential, Cooling and Pressure Drop:
When crude oil moves from the formation into the wellbore, there is a significant pressure drop and cooling due to the expansion of oil and gas at the face of the formation. There is also a buildup of streaming potential in the formation due to the flow of petroleum. Asphaltenes will start depositing at the formation due to the cooling as well as the electrostatic effects because of their polar nature. Paraffins soon follow and conglomerate with asphaltenes to form what are known as tarry deposits.

Treatment with Cool Fluid:
Often heavy hydrocarbon buildup in the formation is further induced by the sudden cooling of the formation due to certain workover operations, such as acidizing or other operations that introduce a cold fluid into the formation. When the cold acid, or other fluid reaches the formation it may cool the formation below the cloud point of the oil (temperature at which paraffin precipitates out of solution). Paraffin and asphaltene will fall out of solution and may be deposited in the formation. Once production is resumed, the formation temperature returns to its normal temperature. However, if the formation temperature is not significantly higher that the cloud point of the oil, the precipitated wax will not melt and thus will stay permanently in the formation, unless removed by other means.

Hot Fluid Treatment:
Damage to the formation could be caused by hot oiling or hot water treatment. This occurs when the hot fluid and the melted wax reaches the formation, and the formation temperature is below the cloud point of the hot fluid, much of the melted paraffin will precipitate in the formation. This can lead to a significant permeability decrease and formation damage. Note: The addition of PARC400® to the hot oil can minimize or eliminate formation damage by hot oil due to its enhanced solvency effects and crystal modifier properties.

Solvent Treatment:
Formation damage could also be caused by common solvents that have been saturated with paraffins. If the saturated solvent is left in the formation for an extended period of time, much of the dissolved paraffin will precipitate out of solution and recrystallize. This sometimes causes blockage in areas that had no paraffin buildup in the first place.

Deposits in the Tubing and Production Lines
After the oil and gas leave the formation and move up the well, the pressure and temperature will continue to drop and wax may be deposited in the tubing, flowlines, storage tanks, and equipment. Generally the deposits begin in tubing and increase as the crude oil cools.

It is important to note that once a thin film of hydrocarbon deposit is formed on a surface, the rate of further deposit accumulation is drastically increased, thus the typical production drop curve associated with waxing off is observed.

As the well gets older, the well usually develops an increase in paraffin and asphaltene problems because of the following:

1. Over time, oil quality changes to a heavier grade which naturally contains more paraffin and asphaltene.
2. As the reservoir pressure drops, oil production decreases; thus, the flow rate decreases, resulting in larger temperature gradient in the well conduit. This results in lower temperatures within the well, which leads to more hydrocarbon accumulation.
3. The decrease in production leads to slower flow of oil, which provides more opportunity for accumulation of deposit and less scraping effect of the slow moving oil.

Unless the deposits are removed, the operator is often faced with a decrease in production, increase in pump problems, waxing off of the tubing and other production lines, and a possible total loss of production.

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