This case study focuses on a Middle East giant carbonate oil field drilled with horizontal producers and water injection wells. In this particular field, formation pressure while drilling measurements are primarily used to characterize the mobility of the formation fluid, to ensure injectors are optimally placed in good injectivity intervals and producers in high productive zones. Acid stimulation is required to mitigate drilling induced reservoir damage. Owing to the length of the open hole sections and the high heterogeneity of the formation mobility, effective placement of acid is very challenging. Viscoelastic diverting acid is commonly used to assure good zonal coverage across each stimulation stage, but the length of the extended reach wells requires optimum diverter placement for cost effectiveness.

An innovative methodology using distributed temperature surveys (DTS) with fiber-optic enabled-coiled tubing was introduced to compare pretreatment injectivity with the mobility profile acquired while drilling before formation damage has occurred. The predicted injectivity/productivity profile computed from mobility measurements is used to establish the fluid placement strategy during the prejob planning stage to decide on the required amount of acid and diverter. During the matrix stimulation operation the temperature profiles after an injectivity test are compared with the baseline DTS temperature and mobility profile to identify thief zones and intervals with drilling damage. The availability of this information at the well site during the acid treatment allows the selective placement of diverter fluid across the thief zones, verification of the effectiveness of the diversion, its distribution along the wellbore, and accurate spotting of acid across damaged zones.

By implementing this process, under stimulated intervals close to the heel section, which has longer exposure time to the drilling fluids, were identified. The current practice of pumping alternating stages of acid and diverter for certain lengths of wellbore segment has been revised and a new optimized approach was introduced. The new methodology has been applied to several wells and has allowed a better use of available treatment fluids to obtain more even injectivity/productivity profiles and maximize stimulation effectiveness.