CO2H HO HO2C Pretreatment N N CO2H
chelant significantly increases permeability in the damaged cores (left).
Posttreatment
In aggregate, the laboratory results on carbonate and sandstone samples provide an advance in overcoming problems associated with acidizing in high-temperature environments. In contemplating the scale-up of laboratory data to actual field operation, treating carbonates repre - sents a more direct extension of the tech nology since secondary precipitation reactions are not present. Complex, multilayer sandstone forma - tions present a more difficult problem since both complicated mineralogy and precipitation reactions must be considered. Job success in sandstones can be improved by using a geo - chemical simulator package called Virtual Lab software that optimizes stimulation parameters for a variety of fluids and bottomhole conditions (next page, left).15
Field results from the application of these advances in high-temperature acidizing confirm their potential.
4 5
2 3
0 1
24% carbonate sample
12% carbonate sample
> Sandstone and chelants. Laboratory permeability tests were carried out on Nemba sandstone cores with varying carbonate levels before and after coreflood treatment with sodium HEDTA at 149°C (bottom). In the 24% carbonate sample, the chelant increased permeability (k) by a factor of 25. In the 12% carbonate sample, permeability increased by 35%. Samples of the cores were photographed using a scanning electron microscope before and after treatment with an HEDTA chelant. Before treatment, the sandstone shows pore blocking as a result of dolomite and chlorite particles in addition to quartz overgrowth. After treatment, the sample shows significant removal of the pore-blocking minerals.
k (final) k (initial)
Acidizing High-Temperature Carbonate Wells The carbonate reservoirs of the Smackover formation, located in the southeastern USA, have been prolific producers of oil and gas since their initial discoveries in 1937.16
Although interest in
this formation continues, many of the wells drilled years ago now require stimulation to boost declining production. High-temperature gas wells drilled in Alabama Smackover dolomite 20 years ago have been acidized with good results using oil-HCl emulsions.17
These retrograde
15. Ali S, Frenier WW, Lecerf B, Ziauddin M, Kotlar HK, Nasr-El-Din HA and Vikane O: “Virtual Testing: The Key to a Stimulating Process,” Oilfield Review16, no. 1 (Spring 2004): 58−68.
16. “The Smackover Formation,”
http://www.visionexploration. com/
smackover.htm (accessed October 20, 2008).
17. Navarette et al, reference 8.
18. The composition of the emulsion as % by volume was 30% of an HCl solution (20% by weight HCl in water) mixed with 70% diesel oil.
19. Nasr-El-Din HA, Solares JR, Al-Mutairi SH and Mahoney MD: “Field Application of Emulsified Acid- Based System to Stimulate Deep, Sour Gas Reservoirs in Saudi Arabia,” paper SPE 71693, presented at the
SPE Annual Technical Conference and Exhibition, New Orleans, September 30−October 3, 2001.
20. Cocoalkylamine is a cationic surfactant that includes high concentrations of several long-chain acids that include lauric, myristic, palmitic and caprylic varieties.
21. Nasr-El-Din HA, Al-Dirweesh S and Samuel M: “Development and Field Application of a New, Highly Stable Emulsified Acid,” paper SPE 115926, presented at the SPE Annual Technical Conference and Exhibition, Denver, September 21−24, 2008.
22. Like the cocoalkylamine, tallow amine acetate is a cationic mixture of acids. However, this emulsifier has longer carbon chains and contains some double bonds.
23. Frenier et al, reference 10.
condensate wells reach a depth of 18,500 ft [5,640 m] and can attain bottomhole tempera - tures of 320°F [160°C] and static bottomhole pressures of 2,500 to 4,000 psi [17.2 to 27.6 MPa]. The treatment and production history of one of these wells illustrates application of retarded emulsions at high temperature in carbonates. The gas well treated in the Alabama Smackover field with a retarded oil-HCl emulsion was drilled and completed in 1986. By 1998, gas and condensate production from the well had declined significantly. Prior to treating the well with the emulsion, two workover operations were performed. First, withdrawal of a chemical injection string allowed additional perforations. Next, tubular scale was removed using 15% HCl. This well was then treated with nearly 214 bbl [34 m3] of an HCl-diesel emulsion at a rate of 9 bbl/min [1.43 m3/min].18
Immediately after
treatment with the retarded emulsion, gas production more than doubled, with a smaller but
58
Oilfield Review
Permeability, mD
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