The wells in an oil field in East Venezuela have a bottomhole static temperature of approximately 230°F and varied mineralogical composition from interval to interval. Near-wellbore fines damage and carbonate scale damage have been reported in these wells. Currently, various formulations of mud acids, organics acids, and solvents are used to treat these wells with mixed results.

A novel chemical system has been developed for the stimulation of high-temperature sandstone reservoirs. By introduction of unique chemical mechanisms, the new sandstone acidizing system

  1. reduces the multiple stages in traditional sandstone acidizing to one stage;

  2. minimizes precipitations by delayed and stabilized reaction mechanisms;

  3. provides homogeneous dissolution of formation;

  4. has a much lower emulsion and sludge tendency than conventional fluids as well as lower corrosion rate; and

  5. stimulates sandstone reservoirs at high temperature by effective damage removal and further matrix dissolution.

Acid solubility, ion concentration, and mineralogical analyses indicate that the sandstone formation in this well has high content of iron-bearing minerals and a moderate content of sensitive clays. Results of core flooding tests conducted on the damaged field cores show that both mud acid and organic clay acid systems show secondary damage on the formation core sample during the acid preflush. Additionally, mud acid shows further damage after the treatment. In contrast, the new fluid system shows consistent damage removal during the treatment with the highest regained permeability. Geochemical simulations also show that more skin reduction is obtained with the new fluid than with the other conventional acid systems tested.


The oil field is located in Maracaibo, Venezuela. The BHST in wells ranges from 220 oF to 240oF. Most of the wells have numerous perforated intervals stretching up to 1000 ft (of which up to 500 ft is perforated). The mineralogy varies from interval to interval, with 4–16% CaCO3, 6–18% clays (mainly kaolinite), 5–10% feldspars, and siderites in some wells (2–5%). The reservoir pressure in zones ranges between 800 and 2500 psi and skin varies across the zones. The rock permeability varies from 1 mD to 200 mD among the zones. The main formation damage mechanisms were identified as fines migration (80–90% production decline after treatment) and CaCO3 scales, mainly due to loss of workover fluids.

Currently, various formulations of mud acid, organic clay acid, and solvents are being used to treat these wells with mixed results.

The new sandstone acidizing system is developed to effectively treat multi-layered high temperature (200–375oF) reservoirs with long production intervals and complex mineralogy. The benefits of the new sandstone acidizing fluid, which utilizes a novel chemistry, include simplified placement process (i.e., single stage), less precipitation tendency, reduced tubular and production equipment corrosion, and less exposure of hazardous fluids to personnel and the environment at the wellsite. These benefits ultimately lead to a high success rate of sandstone acidizing and sustained production increase from high temperature sandstone reservoirs.

A comprehensive laboratory study, which includes acid solubility tests, X-Ray Diffraction (XRD) analysis, batch reaction kinetics, fines migration tests, core flow tests, was conducted on field cores to evaluate and compare the performance of the new sandstone acidizing system with current systems being used in the above oil field.

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