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Simulation, Design and Application of Acid+Proppant Stimulation in a Carbonate Reservoir


 The application of acid fracturing techniques to deeply buried carbonate reservoirs is often an attractive option due to acid's ability to penetrate/improve natural fracture production where a gel frac fluid may damage the natural fractures. However, effectiveness of acid can be limited due to depth, temperature, and high in situ stress. The introduction of acid creates surface roughness or asperities that hold the fracture open under reservoir conditions, but all three factors above diminish the applicability of acid etched fractures. Under extreme stress these fractures close unless artificially propped open in some fashion. The advantage of combining the two approaches (acid+proppant) is not only an improvement in the natural fracture conductivity through the acid etching, but also yields a longer lasting conductivity in the main fracture from the emplacement of the proppant.
 The idea of adding proppant to an acid fracture stimulation job has a long history but has seldom been used due to a fear (not unfounded) of proppant flowback, and the lack of design tools to quantitatively identify proper candidates. Additionally, models based upon the classic Nierode-Kruk correlations were often over-optimistic in predicting fracture conductivity under high stress conditions, disguising the potential need for combination treatments.
 Recent developments in modeling, especially the upscaling of laboratory data to field-scale, make it possible to evaluate the combination of both techniques. The completion design and post-test analysis of two recent acid+proppant stimulation programs in Middle-East carbonate reservoirs is examined. Case 1 was a 10m interval at a depth of 3600m (11,800 ft). Closure stress was 700 bar (10,000 psi). Case 2 was a 35 m thick interval at a depth of 2200 m (7000 ft) with an average porosity of 20% and permeability of > 5 mD as determined from wireline logs. Reservoir temperature/pressure for this case were 120 C (260 F) and 250 bar (3600 psi), with an in-situ closure stress of 350 bar (5100 psi). The formation was characterized by the homogeneous distribution of porosity/permeability.