news

The F reservoir in Iraqi Oilfield A has low permeability and few natural fractures, most of which are microfractures with poor conductivity. Matrix acidizing is one of the important stimulation measures for carbonate reservoirs and has achieved certain production improvement effects in the early stage. However, matrix acidizing can only remove near-wellbore damage and has a limited treatment range. For thick reservoirs, the acid may not reach the deep formation. Analysis of the historical matrix acidizing results in the F reservoir shows that 67% of the wells achieved an oil increase of more than 159 m³/d after acidizing. However, wells/layers with poor physical properties generally showed mediocre results, and 11% of the wells had no production improvement at all. Relying solely on acidizing cannot meet the designed production capacity requirements, so a new stimulation model must be explored. Acid fracturing can remove formation damage over a wider range, so large-displacement and large-volume acid injection should be used to expand natural fractures, connect deep formation fractures, increase drainage volume, and mobilize reserves in far-wellbore areas, thereby maximizing single-well productivity.

A study was conducted on the acid fracturing fluid system, and the optimal treatment process was determined as “alternating injection of gelled acid and self-diverting acid + chemical particle/fiber filtration-control acid fracturing + conventional acid closure acidizing.” Using simulation software, the acid fracturing scale, acid volume, injection rate, and acid intensity for the F reservoir in Oilfield A were simulated. Two simulation methods were employed: the first involved simulating fracture geometry using different injection rates while keeping the acid volume and acid intensity constant; the second involved simulating fracture geometry using different acid volumes and acid intensities while keeping the injection rate constant. Based on the two sets of fracture geometry simulations, preliminary conclusions were drawn. For the F reservoir in Oilfield A, the optimal injection rate for alternating gelled acid and self-diverting acid is 4 m³/min, with an acid intensity of 8 m³/m. The optimal acid-etched fracture length is 60 m, and the optimal permeability per centimeter of fracture is 20 D/cm. According to the actual conditions of the target well, the acid fracturing interval was determined to be 4,050–4,100 m, with an estimated formation breakdown pressure of 70.1 MPa. The designed maximum surface pumping pressure is 65 MPa, the casing–tubing annulus balancing pressure is 10–20 MPa, the injection rate for gelled acid is 4–5 m³/min, for self-diverting acid is 3–4 m³/min, and for closure acid is 1–1.5 m³/min.

The gelled acid and self-diverting acid can meet the performance requirements of retarded reaction, corrosion inhibition, non-uniform etching, and efficient flowback. They can effectively improve fracture conductivity and further enhance the conductivity of acid-etched fractures in the near-wellbore zone.

Before subsequent acidizing operations, the oil–water contact must be clearly identified, and logging tools that are insensitive to salinity should be preferred. Leakage should be controlled during the operation. If lost circulation control is required, the potential impact on subsequent acid fracturing operations must be considered.

Based on the results of mini-fracture analysis and temperature testing, the main fracturing parameters should be readjusted to avoid fracturing into water zones. A more conservative approach should be adopted to reduce the possibility of fractures propagating into water-bearing intervals and to keep the treatment as far away from water zones as possible.

There were no previous acid fracturing cases in this area. As the pilot acid fracturing well in the oilfield, this well has accumulated valuable experience and provides important guidance for the subsequent implementation of staged acid fracturing and hydraulic fracturing with proppant in horizontal wells.