Production logging in horizontal wells has been challenging due to phase stratification and complex flow regimes. New technologies were introduced to properly characterize such flow dynamics; however, adding a new complex completion strategy, such as a slotted liner, raises the challenge to a new level. When a slotted liner is not equipped with a hanger, two flow paths become possible—one inside the slotted liner and the other outside it—with possible fluid exchange between the two paths. Production logging tools can only see the inner flow. The lack of information about the outer flow raises uncertainties about the real producing zone(s) and may affect the success of future well intervention operations. We describe a new methodology that combines multiphase production logging measurements with distributed temperature survey data. Both sets of data were acquired simultaneously during conveyance of the production logging tool on coiled tubing. The production logging data offers insights into phase distribution and enables production profiling inside the slotted liner; distributed temperature data solves for total formation production. Combining the two interpretations enables quantification of flow in each of the two paths and helps identify the fluid exchange between them, which would otherwise be misinterpreted as fluid entry from the formation. The result of this integrated interpretation methodology is accurate determination of zonal contributions.

Berkine basin is one of the main oil producers in Algeria. The upper, middle, and lower TAG-I are the target oil-bearing sands. In this basin, the ROD field is under pressure maintained mainly through water injection together with, to a lesser extent, gas injectors. The southern part of the field, "ROD Tail" has four water injectors targeting the middle TAG-I. In recent evaluation conducted through pressure measurement and an interference test, reservoir pressure was found to have declined by 35 bar within 2 years. This has prompted questions about reservoir management, mainly about the effectiveness of injector well capacity in maintaining reservoir pressure. Extensive data were gathered through well intervention; cleanout, perforation, and a caliper log. Many failed acid jobs were also noted in the history of these wells. An engineered high-pressure jetting operation via coiled tubing was executed, but injectivity could not be restored. A methodology and workflow were adopted to identify the source of formation damage and scale deposition in the near-well area and around perforations. Solid samples were collected from the well and sent to laboratory to characterize formation damage type. The injection water was also analyzed by performing a standard 12-ion concentration analysis. An aqueous model simulator was used to confirm that the water was supersaturated with CaSO4 and CaSO4.2H2O. Finally, clay acid treatment was found to be effective. The treatment fluid was designed to prevent proppant dissolution and to clean fracture matrix interface. This was the first time this type of operation was executed after many unsuccessful conventional acidizing operations. Excellent results were obtained after the acid stimulation treatment. The injection rate was found to increase significantly from 120 m3/d to 360 m3/d. Water injection pressure was also found to decrease from 243 bar to 220 bar, and the injectivity index increased by three times. Near-wellbore formation damage was removed, and formation permeability recovered. The clay acid treatment was applied to other wells in the field and similar results were obtained.