Improving Acid Coverage in a Naturally Fractured HPHT Carbonate Reservoir by Combining Chelating Fluids and Chemical Diversion Optimization

Abstract

Uniform distribution of stimulation fluids in a naturally fractured reservoir with high permeability contrasts and a long open hole configuration (more than 800 m) requires an efficient temporary blocking of the preferential zones to allow the fluid to be diverted towards zones with less admission. While having bottomhole temperatures above 175°C means that controlling reaction rates and achieving effective etching to allow appropriate penetration into the invaded zone will be required and thus eliminate skin damage caused during drilling and completion. Therefore, accomplishing the optimal stimulation involves improving not only acid etching efficiency, natural fractures connectivity and adequate fluid penetration, but also achieving homogeneous fluid distribution throughout the interest zone to assure production enhancement. A chelating base fluid system was formulated based on reservoir evaluation through an engineering process that involved numerous laboratory tests, such as rock dissolution capability, acid etching patter analysis, acid spending time evaluation, corrosion control, and compatibility with reservoir fluids, while optimal diverting agent was carefully selected using advance CFD modeling to confirm diversion effectiveness to uniformly distribute fluids under bottomhole conditions and complex well configuration. Finally, stimulation treatment was defined considering fluid invasion, skin removal and productivity analysis. This paper discusses laboratory tests and modeling results as a coupled engineering process to improve acid coverage during an actual implementation in a HPHT well. Laboratory results confirmed that the smart fluid system can create long conductive channels increasing conductivity by dissolving rock formation and prevent by-products precipitation. On the other hand, CFD results demonstrated that the application of multi-stage chemical diversion pills at specific conditions (flow rate, volume, rheology) optimizes fluid distribution. Oil production increased from 3,973 to 4,375 BPD and gas production from 10.0 to 13.4 MMSCFD (½"choke) after executing the stimulation job. Wellhead pressure registered before was 3,845 psi, and after the job increased up to 5,276 psi. Successful stimulation was confirmed with bottomhole conditions which showed an increase of 2,045 psi and 5°C, logged through a bottomhole sensor while the productivity analysis allowed to support skin damage reduction from S=76 to S=0.