UNDERSTANDING PARAFFIN AND ASPHALTENE PROBLEMS IN OIL AND GAS WELLS

Based on a workshop sponsored by PTTC's South Midcontinent Region held on July 16, 2003 in Smackover, Arkansas at the Arkansas Natural Resources Museum

BOTTOM LINE

Although often mentioned together, paraffin and asphaltene are distinctly different in their composition, their behavior and the conditions that lead to deposition. Controlling paraffin and asphaltene problems requires one to understand the conditions that lead to deposition and the different solutions and when each is appropriate. When "total" costs of not treating are considered, chemical solutions are often economically attractive.

PROBLEM ADDRESSED

Paraffin and asphaltene problems can significantly affect well/lease profitability, causing troublesome operational issues, damaging formations and decreasing production. Understanding the nature of paraffin and asphaltene, the conditions that lead to their becoming problems, and solutions for controlling them are important. Speaking from decades of experience, the speaker focused on chemical solutions. 

KEY WORDS:

Asphaltene, Chemical Treating, Laboratory Testing, Paraffin, Prevention And Removal

SPEAKERS

Ken Barker, Baker Petrolite, St. Louis, Missouri

TECHNOLOGY OVERVIEW

Nature of Paraffin and Asphaltene
Paraffins are a continuum of high molecular weight alkane [C(n)H(2n+2)] saturated hydrocarbons that exist in crude oil. Size can exceed C₁₀₀ with either a normal or branched structure. Normal paraffins exhibit higher melting points than equivalent-sized branched structures. The longer the paraffin (higher carbon #), the higher the melting point. This means the larger molecules come out of solution first, so the deepest downhole deposits would be the higher molecular weight paraffins. This means one should analyze the deposit that one is trying to treat (i.e., get a downhole sample from the depth where the problem is occurring, not from the surface). Initially paraffins are in equilibrium in the reservoir under certain temperature-pressure conditions. Once this equilibrium is disturbed by production and temperature-pressure conditions change, deposition may occur.

The temperature at which paraffin begins to come out of solution is defined as the cloud point. Cloud points of crude from different wells within a field can vary as much as 30 degrees F. Pour point is defined as that temperature where the crude sample becomes solid. Paraffin deposits contain 60% or more oil. Paraffin floats on water and is soluble in xylene, n-heptane and crude (generally linear hydrocarbons). A simple field test to determine if a deposit is paraffin is to place a sample of the deposit on aluminum foil on a vehicle radiator cap. If paraffin, the deposit will melt. 

Asphaltenes are high molecular weight, complex aromatic ring structures containing O, N, S and heavy metals. They give crude oil their color. Heavier, black-oil crudes will typically have higher asphaltene content. Being a polar molecule, asphaltenes adsorb to formation surfaces, especially clays. They can oil wet formations, which will increase water flow. Unlike paraffin that is soluble in crude, asphaltenes are a colloidal dispersion. Although not a solution but colloidially dispersed, asphaltenes will not show up in a grindout by centrifuge. With their aromatic ring structure, asphaltenes are not soluble in straight chain alkanes (hexane, heptane). They are soluble in aromatic solvents like xylene and toluene. Unlike paraffin deposits that melt, asphaltene deposits decompose, softening like road tar or even turning into coke-like deposits. 

Causes of Paraffin and Asphaltene Problems
Paraffin deposition is a thermally driven process. Cooling during production, such as occurs from the loss of gas during production, causes wax to precipitate as temperature drops below the cloud point. The % paraffin in a crude oil is not an indicator of potential paraffin problems, rather it is the cloud point AND % paraffin that indicates the magnitude of potential problems. Viscosity and flow rate affect paraffin deposition. High viscosity reduces transport to cold surfaces, reducing deposition. High velocity results in harder deposits. Paraffins cause problems through deposition (formation, tubing, flowline, pipeline), settling (tank bottoms, interfaces), and solidification (high viscosity can cause problems restarting or require very high pressures to pump). 

Paraffin problems result from: (1) natural causes (temperature loss, high volumes of production even if paraffin content is relatively low, gas expansion, pipe cooling due to groundwater aquifers, low surface temperatures), (2) solvent loss (dropping below bubble point, gas production, gas separation, hot oil treatments, heater treaters), and (3) well maintenance operations (temperature drop, water injection, cooling equipment, gas lift, acid/frac jobs with cold fluids). 

Although common, hot oiling can have very adverse effects, including formation damage. Hot or cold water/chemical is strongly preferred. In a DOE-funded effort, Sandia National Labs developed a PC-based software program that reliably models downhole paraffin removal with hot fluid (oil or water) injection and Joule Thomson Cooling. Barker assisted Sandia in developing this program. The program can be obtained by emailing him. The program helps visualize just what is happening during treatments or gas production, and it allows one to see effects for different treating options. 

Incompatible liquids (acid jobs, condensate treatments, crude blending) destabilize micelles leading to asphaltene precipitation. Very high gas-liquid ratios as are encountered in CO₂ floods or gas wells can also cause precipitation. Asphaltenes tend to bond to charged surfaces, especially clays. High velocity flow creates a charge that can exacerbate precipitation. Field problems include formation plugging, oil wetting of formations that leads to high water production, filter plugging, high viscosity fluid that causes high pumping pressure, coated solids, difficult to treat emulsions, tank bottoms and interfaces in vessels. Sludging with acid treatment is common. To minimize sludging, a two-step treatment process is recommended. First treat with crude containing chemical, followed by acid. 

Paraffin and/or asphaltene problems can cause formation damage. Reviewing production decline and well history can identify damaged wells. Focus particularly on treatment history (acid, frac) and subsequent response. Wells that have been hot oiled multiple times down the tubing will often be damaged. Field personnel can often provide essential observations not evident in well records. Laboratory testing helps design effective chemical treatments. 

Laboratory Testing
Paraffin lab tests include oil analysis, cloud point, pour point, cold finger, dispersant, flask, and solvency/cloud point reduction. With Baker Petrolite, cross-polarized microscopy (visually see crystals as they form) is now the standard for cloud point determination. The cold finger test and ASTM D97 pour point test are commonly performed tests. Flask and centrifuge tests with representative paraffin samples, crude oil and chemicals being considered help determine the most effective chemicals. Since the rate at which cooling occurs affects paraffin deposition, lab testing for some applications may need to be tailored to duplicate field conditions. 

Asphaltene lab testing includes: (1) oil analysis (Saturates, Aromatics, Resins, Asphaltenes or SARA), (2) solids analysis for asphaltenes, (3) oil stability (SARA and Colloidal Instability Index (CII)), oleinsis spot test, hexane precipitation, SDS or high-pressure solids detection), (4) contact angle (related to wettability), (5) deposit solution, (6) adsorption/removal and (7) rigid film emulsion. CII testing, which determines the ratio of bad components (Saturates + Asphaltenes) to good components (Asphaltic Resins + Aromatics), provides an indicator of asphaltene instability. Ratios above one mean that those crudes are unstable and precipitation is likely. 

Chemical Treatments for Paraffin Control
Common chemical solutions for paraffin control include: (1) solvents, (2) mutual solvents, (3) water/dispersants (4) oil/dispersants and (5) crystal modifiers (PPD's- Pour Point Depressants). Solvents actually dissolve paraffin deposits, so large quantities are typically required. Solvent ability will depend on the nature of the paraffin itself. As a point of reference, xylene will dissolve just over 6 lbs of C₃₆ paraffin per 100 lbs of solvent at 100 degrees F, < 1 lb. at 50 degrees F . The treating procedure must ensure that the solvent is actually in contact with the deposit and that adequate soak time is provided for dissolution.

Water/surfactant dispersants work by penetrating the deposit and then dispersing the paraffin. Laboratory testing helps determine the best performing chemical and appropriate concentration. Fresh water is recommended over brine in field treatments. Providing adequate contact time is critical. Designed properly, water/surfactant dispersants can be very cost effective for managing paraffin problems. Oil/dispersant treatments disperse the paraffin, help wet pipe surfaces and prevent sticking. 

Batch treatments are common. Continuous treating is typically used for more severe paraffin problems. For very severe problems, wax crystal modifiers may be required. Chemical performance depends upon the crude oil, so laboratory testing is required. Wax crystal modifiers are applied continuously or through squeeze treatments. 

Chemical treatments for removing asphaltene include: (1) solvents, (2) dispersant/ solvents, and (3) oil/dispersants/solvents. The dispersant/solvent approach is used for removing asphaltenes from formation minerals. Continuous treating may be required to inhibit asphaltene deposition in the tubing. Batch treatments are common for dehydration equipment and tank bottoms. There are also asphaltene precipitation inhibitors that can be used by continuous treatment or squeeze treatments.

Economics—Total Cost of Operations
When evaluating paraffin and asphaltene control options, cost of the chemical treatments must be evaluated against "total" costs incurred should treatment not be performed. Those costs could include rig costs, downhole failures, high electric loads, down time and deferred production, etc. Failure to identify and quantify total costs may cause chemical treating to appear to be less cost effective than it actually is.

CONNECTIONS:

Ken Barker
Baker Petrolite
369 Marshall Avenue
St. Louis, MO 63119-1897
Phone: 314-968-6001 Fax: 314-968-6013
Email: Kenneth.barker@bakerpetrolite.com

For information on PTTC’s South Midcontinent Region and its activities contact:
Charles Mankin, Director, Oklahoma Geological Survey
100 E. Boyd St., Room N131, Norman, OK 73019-0628
Phone 405-325-3031, Fax 405-325-7069, Email cjmankin@ou.edu 

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