Preventing Sludge

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The potential for Sludge, Asphaltene and Mineral Scale Deposition Can Be Recognized Early Using Oil Geochemistry and Water Geochemistry.

   


Preventing sludge formation when different oils are commingled in a flow line

Commingling compositionally distinct oils in a flowline may reduce the solubility of asphaltenes and/or high-molecular-weight paraffins in the commingled oil, resulting in precipitation of these components in the flowline. This problem is especially prevalent when an asphaltene-rich, carbonate-sourced oil is mixed with a much lighter crude. By clogging tubing, these organic precipitates may reduce flowline performance. This type of problem can be avoided by conducting very inexpensive oil-mixing experiments in the laboratory. If such experiments identify significant risk for formation of organic precipitates, then additional experiments can identify chemical modifiers that can be added to the production stream to prevent formation of organic precipitates by increasing the solubility of asphaltenes and/or high-molecular-weight paraffins.

Preventing down-hole sludge formation from various well treatments

Various well additives may form sludges downhole by forming oil-water emulsions or by reducing the solubility of asphaltenes and/or high-molecular-weight paraffins in the oil, resulting in precipitation of these components in the well bore and near-well-bore region. By clogging pore throats, these organic precipitates may adversely affect the producibility of the reservoir, and may necessitate expensive remedial treatments, such as hot toluene or xylene washes. This type of formation damage can be avoided by conducting core flood experiments in the laboratory that assess the affect of the additive on the reservoired oil.

Minimizing formation damage during a reservoir flood

During either a miscible CO2 or hydrocarbon gas flood, dissolution of injected gas into the oil may reduce the solubility of asphaltenes and/or high-molecular-weight paraffins in the oil, resulting in precipitation of these components in the reservoir. By clogging pore throats, these organic precipitates may reduce injectivity, adversely affecting the producibility of the reservoir. This type of formation damage can be avoided by conducting core flood experiments in the laboratory that assess the affect of the injectant on the reservoired oil. If such experiments identify significant risk for formation of organic precipitates, then additional experiments can identify chemical modifiers that can be added to the injectant to prevent formation of organic precipitates by increasing the solubility of asphaltenes and/or high-molecular-weight paraffins in the oil/gas solution (Hwang et al., 1999).

Diagnosing the Cause of Inorganic Mineral Scale Using Water Geochemistry

Water geochemistry can be used to diagnose the cause of precipitation of mineral scales (e.g., barite, calcite, silica, iron oxide, halite) in flow-lines, valves, gauges and other surface equipment by identifying the mixing of geochemically incompatible formation fluids at surface facilities.

For more information on the techniques described here, or to discuss a specific project, e-mail us at oiltracers@weatherfordlabs.com, or call us at U.S. (214) 584-9169.

References

Hwang, R. J. and Ortiz J. (1999). Mitigation of asphaltics deposition during CO2 flood. Abstracts 19th International Meeting on Organic Geochemistry, Istanbul, Turkey, Tubitak Marmara Research Center Earth Sciences Research Institute. Vol. II: 601-602.

 

The potential for Sludge Formation and Asphaltene and Mineral Scale Deposition Can Be Recognized Early By Using Oil Geochemistry and Water Geochemistry.