Combination of CO2 Foam and Fit-For-Purpose Fluids During Acid Fracturing Revive Potential of a Jurassic Well in a Depleted, High-Temperature Carbonate Reservoir in North Kuwait

Abstract

Abstract Located in Kuwait, the maturing Middle Marrat formation in the Raudhatain field faces many challenges, some of which are sustaining hydrocarbon production, efficient post-fracturing formation cleanup, and well flowback operations because of reservoir depletion. A functional solution to these challenges was achieved by implementing one of the first trials in Kuwait for a fully energized acid fracturing technique using enhanced stimulation fluids. The main challenges of stimulation in this depleted reservoir are the need for extended post-fracturing formation cleanup and the nitrogen lifting needed to unload the injected treatment fluids. This leads to higher operational costs due to additional intervention and the subsequent prolonging of the time until the wells are put on production. To tackle these challenges, high-retained-permeability acid fracturing fluids foamed with carbon dioxide were considered in the treatment design. The main benefits of energizing fracturing fluids using carbon dioxide (CO2) are the better fracture cleanup due to expansion of the stored compressed gas in the liquid CO2, fluid loss control that is provided by foam, minimized fracture conductivity damage, and higher hydrostatic pressure while pumping that translates to lower surface pressures during injection. The pad fluid system used as part of the fracturing technique is among the latest developments in the hydraulic fracturing products. It possesses a good rheology and high retained permeability and is simple to apply. In combination with the acid systems and CO2 foam, it can develop effective, high-conductivity fractures in high-temperature carbonate reservoirs. The pilot foamed fracturing treatment was carried out successfully, applying high injection rates and alternating a specifically designed low-polymer pad fluid with straight 15% hydrochloric acid and viscoelastic diverter in several cycles. The designed foam quality for the treatment was 40% with maximized pumping rate within the surface pressure limitation throughout the job. The desired levels of fracture face etching, leak off control, and fracture geometry development were all observed and substantiated by the treatment injection pressures and the post-treatment fracture modeling results. Although there was a substantial reduction in operational cost to the operator, a significant reduction in produced sour gas flaring time was made possible upon completion of the pilot job, which ultimately led to an earlier connection of the well to the production facility. The pilot well's net production gain was estimated at an additional 1,150 STB/D[SD1] of oil and an approximate 4 MMSCF/D of gas upon completion of the treatment, complete flowback and formation cleanup. The resulting time and cost savings as well as the increased incremental well productivity confirmed high perspectives for the implemented foam acid fracturing approach.