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Abstract Gas wells, coal seam methane wells, glycol dehydrators, gas plants and gas storage wells can all experience paraffin problems that affect the cost to produce and handle gas. Problems with paraffin have been encountered from the formation through the gas plants to the storage wells. This paper will explain what paraffin is, why the problems occur and what type of treatments have effectively treated gas system problems. Case histories of various types of successful and unsuccessful treatments will be presented. Introduction Gas wells and coal seam methane wells may produce high gravity crude oil (> 40 API) or condensate (> 50 API) with the gas. Some wells may produce no liquids to surface but will still be producing oil or condensate into the well bore. The paraffin or n-alkane components account for a significant portion of a majority of these oils and condensates. These paraffins have a straight chain linear structure composed entirely of carbon and hydrogen. The melting points vary from -295F for methane gas (CH4) to >240F for Hectane (C100H202) and above.1 See Table 1. It is not known what the longest naturally occurring n-alkane in crude oil or condensate is, the longest observed by this author was a C103H208. The paraffins >C20H42 are the ones that can cause deposition or congealing in gas systems.2 These paraffins >C20H42 can deposit anywhere from the fractures in the formation rock to the gas storage wells.3 The deposits can vary in consistency from rock hard for the longest chain length paraffin to very soft, mayonnaise like congealing oil deposits caused by shorter chain paraffin. Crude oils and condensates have congealing points from < -90 F to >130F. Paraffin can cause a great many types of problems including deposition from in the formation to the gas plant, congealing oil, interface problems, tank bottoms, stabilized emulsions, high line pressures, plugged flow lines, paraffin coated solids,

under deposit corrosion, plugging of injection wells and filter plugging.4 One or all of these problems can occur in a gas production system. Many different types of treating programs have been used to control all of the various types of problems in different systems. Down hole problems have been treated by cutting or wire lining, heated tubing, coated tubing, fiberglass tubing, hot water circulation, hot oiling down the tubing, bacteria, magnets, enzymes, steam injection, solvent or condensate treatments, continuous or batch down hole chemical injection and squeeze treatments of crystal modifiers (PPDs). Chemistry of Crude Oil and Condensate The paraffin series of compounds or n-alkanes contain only hydrogen and carbon. The number of carbon atoms can range from 1 to >100. The ratio of carbon to hydrogen atoms can be shown by the formula CnH2n+2. This means that for every carbon atom we will have twice as many hydrogen atoms plus two.1 See Table 1. Reservoir fluids in gas wells are composed primarily of methane, ethane and propane which have very low boiling points. Depending upon a wells temperature and pressure characteristics liquid oil or condensate may be produced. The oil or condensate entering the well bore will contain the longer chain paraffins that give the liquid its cloud point. The cloud point is the temperature at which the longest chain length paraffin present in an oil or condensate becomes insoluble in that liquid. The cloud point indicates the temperature at which paraffin deposition will start. If the formation or equipment surface reaches the cloud point temperature of the liquid, paraffin deposition will start even though the bulk oil is still above the cloud point. As the surface temperatures of the equipment drops below the cloud point shorter chain paraffins will start to precipitate and deposit. The type of paraffin depositing will change as the condensate progresses downstream through the system. The melting point of the deposits will change as the type of paraffin changes. If the system cools sufficiently paraffins of < C36H74 will start to precipitate and will cause the congealing of the condensate itself. Many times congealing condensate will be misidentified as paraffin deposition. The only difference between deposited paraffin and deposited congealed condensate will be the melting point of deposit itself. A rule of thumb of the author is that if the deposit melts at < 120F it is probably a congealing condensate problem. It should be noted that no two oils or condensates are exactly alike in paraffin distribution. The cloud points will vary from well to well in a field, viscosities will vary, production levels

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Paraffin Problems in Gas Systems K. M. Barker, SPE, J.M. Bigler, K. Hake, D. C. Sallee/ all with Baker Petrolite

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and the temperatures of the fluids will vary. These differences between wells will cause the problems to vary enormously from well to well within a field.

Causes of Paraffin Problems Most paraffin problems in gas wells occur because:

1) The reservoir oil or condensate losses the methane, ethane and propane concentrating the long chain paraffin in less fluid volume raising the cloud point.

2) The fluids contact a surface that is cooler than the cloud point of the fluid in the system.

3) Cooling is often related to expansion of gas as pressure drop occurs (Joule-Thomson Cooling).

Cooling of the oil and surrounding environment is caused by a number of well and fluid characteristics. A number of the possible reasons are listed here.

Gas Expansion Cooling In humid regions of the world it is not usual to see ice form on the body of a choke in an oil and gas production system. The reason this ice forms is the rapid expansion of gas molecules across the choke. This expansion is due to the pressure drop across the choke. It is not unusual to see 2000 psig upstream of the choke and 100 psig downstream of the choke. This 1900 psig pressure drop causes a 95F temperature drop in the choke, or 1F per 20 psig of pressure drop. In this example the body of the choke is cooled 95F, and if the temperature drops below 32F, ice forms. The cooling associated with pressure drop takes places wherever a pressure drop occurs; permeability in formation rock, perforations, across pumps, chokes and separators. A computer program is available that can calculate gas expansion cooling 5. See Graph 1. The first time that a well is tested using a pressure drawdown test, paraffin will start to damage the most open flow paths (permeability) in the formation. If the formation temperature is below the melting point of the paraffin that has been deposited, permanent damage has occurred.

Separation of Gas from Reservoir Fluid As gas is separated from the reservoir fluid the long chain paraffin content is going up in the remaining liquid. If a reservoir fluid is 99% by volume methane, ethane, propane and butane and contains 0.1% (>C20H42) paraffin in the reservoir when all the gas is lost the paraffin (>C20H42) become 10% by volume of the remaining fluid. If a large pressure drop occurs at the same time the cooling may cause the remaining condensate (oil) to go solid (congeal). If this occurs it may be possible to produce gas without liquid reaching the surface for a short time before the well plugs. The condensate with the least paraffin by volume is the condensate in the formation. The formation condensate is at a higher temperature and pressure and has the lowest cloud point it will ever have. As methane, ethane, propane and butane are lost from the crude the >C20H42 paraffins are increasing in volume compared to the rest of the crude. The cloud point will also increase as the gas and gas liquids are lost. The most paraffinic oil or condensate in any system is that fluid in the sales tank near the bottom of the tank.

Geothermal Gradient The condensate or oil produced into the well bore will stabilize at the bottomhole temperature and pressure and will flow up the tubing to the surface. The natural cooling of the liquid as it is carried to the surface may allow it to reach its cloud point. If the equipment surfaces cool to the oils cloud point deposition of paraffin will occur. The location may vary from the formation to the pipeline or anywhere in between.

Oil Volume The more gas, oil or condensate that an oil well makes, the more paraffin is being carried through the system. It never sounds like very much when you say the oil contains 2% paraffin by volume until you realize that this is 2 barrels out of every 100 barrels of condensate production. The more condensate a well makes the faster the deposition will be and the more frequent the problems. The higher the volume of fluid produced, the warmer the condensate will reach the surface. This will reduce downhole problems, but may not eliminate them.

Cold Fluids In many operations in the oilfield we have to pump large volumes of fluid into the tubing or annulus. Reasons that we may do this include; killing a well to work on it, acidizing or fracturing the well. If the volume of fluid is larger than the shut in fluid level some of the fluid will go into the formation. If the fluid is pumped at >5 bbl per minute the fluid will reach the formation at near its surface temperature. If a 70F fluid is pumped from a truck on the surface at 5 barrels per minute it will reach 5000 feet down a well and only be 75F. If pumped at 50 bbl per minute it will still be 70F when it reaches the formation. The situation gets much worse if it is January in Oklahoma and the fluid is only 20F in the truck. If the flow paths in a formation are cooled to 20F and the cloud point of the reservoir fluids is 90 paraffin deposition will occur as the produced fluid are being produced and warmed up the near wellbore area. The melting point of the paraffin can be high enough to permanently damage the formation. Types of Problems and Treatments Many different types of paraffin problems have been experienced in gas wells. The following are examples of problems that are possible depending upon the condensate and system conditions being experienced. A certain problem may occur in one system but with a different condensate in an identical system it may not occur.

High Melting Paraffin Formation Deposition At high pressure and temperature in deeper reservoirs, reservoir fluids contain all the gas, gas liquids and other components including the high melting paraffins. As the hydrocarbon mixture flows into the near wellbore and through the perforations pressure drops occur that cause cooling of the formation. If the pressure drop is large enough the formation rock temperature may be reduced below the cloud point of the hydrocarbon mixture and long chain, high melting paraffin may deposit. This paraffin can plug the flow paths in the formation. If the paraffin deposited has a higher melting point than the formation temperature permanent plugging may occur. This deposition can reduce production of gas and liquids very rapidly and may be misidentified as natural decline.

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This type of problem can be removed by solvent treatments and inhibited with crystal modifier squeezes. A deep (13,000 ft), hot (205F) gas well in central Oklahoma had declined from 2 MMCF and 150BCPD to 80 MCF and 40 BCPD in two years. Four solvent/chemical/condensate cleanup treatments restored the well to 750 MCF and 70 BCPD over a years time6.

Congealed Oil Formation Deposition If the reservoir fluids in a gas reservoir are mostly methane, ethane and propane the remaining fluid after they flash off with reduced pressure contains all the paraffin from the reservoir. In some wells the gas free oil that remains congeals due to Joule-Thomson cooling and concentration of the paraffin in a small volume of oil. This may result in a well making no fluids to surface but being plugged by a grease like congealed oil in the formation. Dry gas wells in the San Juan Basin area of New Mexico were suffering from a loss of productivity early in their production life. Acid jobs did not help restore any gas production. Congealed oil was seen on the surface in water tanks of some wells so solvent treatments of the near wellbore formation were tried with great success. Gas production was double or tripled on some wells with one treatment. Squeeze treatments of crystal modifiers can be combined with cleanup treatments if the deposition is found to be a recurring problem that significantly affects production of gas and oil.

Tubing Deposition and Congealing Fluids If oil or condensate is produced up the tubing paraffin deposition can occur if the equipment surfaces drop below the cloud point of the fluid. If the paraffin deposited has melting points of >120F the wells may be wirelined or cut to periodically clean the tubing. If the frequency or time required to cut becomes excessive or other problems are seen chemical treatments may be required to cost effectively treat the problems. Continuous injection down a capillary sting or squeeze treatments may be effective in stopping or slowing the deposition of this paraffin. If the melting point of the deposits is

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as the glycol is circulated over and over. The heavy hydrocarbons help cause emulsion, oil wet solids and plugging problems as the quantity of accumulation increases. Solvents, surfactant and crystal modifier combinations have been used to help clean up glycol systems so that the new glycol will not be contaminated by a dirty system.

Separator Problems Separation equipment is frequently plugged by paraffin due to the pressure drop cooling that is experienced in this equipment. The incoming gas and liquids are cooled rapidly and then encounter spreader plates and mist extractors which can accumulate the paraffin particles that may be present. Any solids or water droplets will add to the volume of the problems and cause reduced efficency of separation. The poor performance of the separator may cause fluids to be carried with the gas to the gas plant. Large solvent treatments may be needed to clean up the separator and continuous treatment may be needed if the separator plugs frequently.

Tank Problems In system making barrels of condensate a day a storage tank will be used. The storage tanks are usually unheated and the fluids usually cool to ambient temperatures. If the temperature is below the cloud point of the fluid paraffin may separate and settle to the bottom of the tank. If only paraffin is present it may be possible to circulate the tank to disperse the paraffin and then sell it. If however, water or solids are present, it may be necessary to treat the fluid with a chemical to drop the water and solids before it can be sold.

Gas Plant Problems Paraffin problems in gas plants usually show up in separation equipment or chillers. Paraffin problems in separators may lead to hydrocarbon fluids being carried with the gas to the chillers. In the chillers the cold surfaces will cause any long chain paraffin present to come out of solution and deposit. A chiller was having plugging problems and an analysis showed the deposit to be C36H74 average paraffin. The gas plant manager indicated that it could not be paraffin as nothing above C10H22 could get through the sock filters in use at the gas line exit of the separator. Analysis of the condensate carried through the undersized separator and through the soak filter showed that the paraffin were present in the condensate but were still in solution in the condensate as it pasted through the sock filters and only showed up as the condensate was cooled on the chiller surfaces. The separation equipment size was increased and no further problems were seen.

Gas Storage Well Problems Gas storage wells can have problems with paraffin, congealed oil and hydrocarbon liquids that are carried with the gas. Problems can occur either as the gas is injected or when it is withdrawn. Injection problems occur because any solid paraffin particles or oil wet solids will plug the permeability of the injection well. If iron sulfide, carbonate scale or salt are oil wet they will not be dissolved by fresh water or acid. In order to remove the solids the hydrocarbon must be removed and the solids water wet so that they can be removed with acid. This damage can affect the withdrawal of the gas as the permeability will be adversely affected.

Gas storage wells in Pennsylvania were analyzed because of low injection and withdrawal rates. The rates had declined over the last two years to extremely low levels. Analysis of side wall cores showed the presense of >60% organics (oil, condensate, paraffin), iron sulfide, calcium carbonate scale, salt and solids. A mixture of surfactant, mutual solvent and acid was applied in a batch treatment to clean up the near wellbore interval at the perforations. Well tests after a treatment showed that the well had gone from 6MMCF to 10.3 MMCF per day with one treatment.

Conclusions 1. Gas wells can have paraffin problems from the formation to the gas storage wells. 2. Paraffin problems in gas wells will vary from well to well depending upon the reservoir hydrocarbon mixture present and system production conditionds experienced. 3. Testing and analysis of the actual deposited material is crucial to effectiveness of any treatment program using solvents or chemicals. 4. The nature of the paraffin problem may change with time, temperature, production rates of hydrocarbon liquids & gas. 5. Treatment programs are available to treat paraffin problems in gas wells. 6. Gas wells may have downhole paraffin problems without producing condensate or oil to surface. 7. Joule-Thomson cooling causes many of the paraffin problems experienced in gas systems. 8. A computer program is available to calculate gas expansion cooling in wells.

Acknowledgements The authors would like to thank Baker Petrolite for permission to present this paper. References 1. Stadler, M.P., Deo, M.D. and Orr Jr., F.M.: Crude Oil Characterization Using Gas Chromatography and Supercritical Fluid Chromatography, SPE 25191, Paper presented at the SPE International Symposium on Oilfield Chemistry, New Orleans, La., March 2-5, 1993, pp. 413 420. 2. Pederson, K.S., Skovborg, P., and Ronningsen, H.P. : Wax Precipitation From North Sea Crude Oils & Temperature Modeling, Energy and Fuel (1991) 5,924. 3. Newberry, M.E., Barker, K.M.: Formation Damage

Prevention Through the Control of Paraffin and Asphaltene Deposition, SPE 13796, paper presented at the SPE 1985 Production Operations Symposium held in Oklahoma City, OK, March 10-12, 1985, pp. 53-58.

4. McClaffin, G.G. and Whitfill D.L.: Control of Paraffin Deposition in Production Operations, SPE 12204 presenteed at the 58th annual Technical Conference and Exposition, San Francisco,CA, October 5-8,1983.

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5. Mansure, A.J., and Barker, K.M.: Insights Into Good Hot Oiling Practices, SPE 25484 , Paper presented at the 1993 Productions Operations Symposium held in Oklahoma City, Oklahoma, March 21-23, 1993, pp. 689-694. 6. Barker, K.M., Sharum, D.B. and Brewer, D.: Paraffin Damage in High Temperature Formations, Removal and Inhibition, SPE 52156, Paper presented at the 1999 Mid-Continent Operations Symposium held in Oklahoma City, Oklahoma, March 28-31, 1999. PHYSICAL CHARACTERISTICS OF SOME N-ALKANES IN CRUDE PETROLEUM Compound Formula Melting Point F Boiling Point F @ 1 atm Methane CH4 -296 - 259 Ethane C2H6 -297 -127 Propane C3H8 -305 -44 Butane C4H10 -217 31 Pentane C5H12 -201 96.8 Hexane C6H14 -137 156 Heptane C7H16 -131 209 Octane C8H18 -70 258 Nonane C9H20 -65 303 Decane C10H22 -21.5 345 Undecane C11H24 -14 385 Pentadecane C15H32 50 519 Eicosane C20H42 97.5 NA Triacontane C30H62 150 579 Tetracontane C40H82 178 NA Pentacontane C50H102 198 790 Hexacontane C60H122 210 NA Heptacontane C70H142 221 NA Hectane C100H202 239 NA Table 1 Graph of Joule-Thomson Cooling

Graph 1

Temperature (F)

In-Situ

Production

Cloud Point

Depth (ft.)

Example Well Data

-1000

-2000

-3000

-4000

-5000

00 50 100 150