Many wells in the Bu Hasa field in Abu Dhabi are completed with near-horizontal or horizontal laterals in the consolidated Lower Cretaceous carbonate formations. These slim barefoot completions allow improved production and drainage from the good permeability formations in the field, however surface production measurements do not tell the full story on the contributing zones downhole. To improve the reservoir management many production logs with specialized logging technology developed for horizontal wells with multiphase flow, are undertaken in the field. This paper presents a case study of one of these wells that was showing less than expected oil production along with a significant but abnormal water cut. Production logging was done to acquire an inflow profile along the lateral, and a pulsed neutron log for formation fluid saturation was also acquired to diagnose any increased water saturation zones. The production profile showed that less than 40% of the open hole lateral length was contributing and that most of the water was coming from a specific section of the well. The formation fluid saturation profile confirmed good oil saturation across the whole lateral as was expected but there was a clearly higher water saturation across the water-producing section of the open hole. Corrective action was taken on the well after these logs with a completion change incorporating various Inflow Control Devices (ICDs) for the lateral section, and gas lift mandrels for improved lifting capability if required in the future. The lateral was then acid stimulated and put back on production. A second production log, again in combination with the pulsed neutron saturation log, was acquired to review the changes in the downhole inflow profile after the completion change. This profile showed that all sections of the lateral were now contributing effectively to the total oil production confirming the effectiveness of the new completion. Water was still coming from the higher water saturation zone that was again observed on the pulsed neutron saturation analysis, however it was apparent that the AICD was controlling the water entry as per design. Surface production measurements indicate reduced water cut and improved oil production confirming good success with the overall intervention. Currently water cut on the well is still slowly but continuously decreasing while the oil production is also improving. Continued monitoring will provide additional feedback for future water conformance operations in the field to assist in improving recovery factor from the reservoir.

During the last decade, some problems have appeared and being affecting the oil production of the mature giant oil field such as: flow boundaries, by pass zones, fractures, etc. hence, the characterization of the reservoir by the integration of static and dynamic data acquired along the field life is required. The new generation of static model is justified in the need to involve the lessons learnt from the previous static/dynamic models with the incorporation of the recent studies and well data. The aim of this article is to integrate the structural seismic interpretation and results of pressure transient analysis obtained from well test, such as distance to potential flow boundaries, average permeability, among others, into the workflow of the new geological static model, through the validation with the conceptual geological understanding of the reservoir. Such workflow not only considers different sources for the reservoir characterization but also reduce the alternative solutions of the well test data to the best-fit solution for the integration. In a typical geological modeling workflow, structural framework is built first, based on the zones definition that include well information, well log data, structural seismic interpretation and the stratigraphic characterization that allow capturing the vertical heterogeneity. Subsequently, the sedimentary-stratigraphic architecture is used as main constrain together with geostatistical methods to distribute the petrophysical properties for each zones. The well test results independently are a punctual dynamic response of the reservoir in a portion of the time and within a certain tested area around the well. However, the integration with the conceptual geological model can resolve the uncertainty that alone cannot respond enable a more robust interpretation of main reservoir heterogeneities. The study proposes the inclusion of the well test data to support and validate, firstly the structural connectivity of the zones through the well test interpretation (validation of faults, dual porosity zones, dense zones, etc.), and secondly calibrate the permeability model with additional dataset than only from cores, which, even though derived from dynamic data, are incorporated in the static model workflow. Implementation of workflow allowed modeling of 48 zones with different petrophysical properties and 122 faults in the static model, which were ranked in three confidence categories. Faults observed by only seismic interpretation were ranked as low, faults calibrated by one of the 57 borehole images logs (BHI) were ranked as mid confidence, and finally, faults that were validated with best-fit result of well test, where interpretation suggest the presence of a boundary as fault and is consistent with the seismic and/or BHI interpretation, is ranked as the highest confidence, inasmuch as the fault is validated statically and dynamically.

Gas Injector Well is part of the project to improve the pressure communication between peripheral gas injectors and nearby producers in the Northern Part of Unit G WAG Patterns. This well was injecting gas only to upper part of Unit G reservoir based on the PLT and TGT results. Based on the study using tracer chemical injection, this upper Unit G reservoir was found to be in connecting with another nearby different reservoir. The initial plan was to re-horizontalize the well and place injector in the proper reservoir, later this was changed and revised to use this innovation technology by installing blank liner with isolating packer to isolate the upper part of Unit G reservoir and let the lower part of open-hole remained open and connected to the required layer of reservoir. After extensive discussion with vendors and performing simulation runs, finally agreed to run this kind of swell packer. Vendor custom designed this kind of innovative packer at their USA facility and transported to ADNOC Onshore yard just before the execution phase. First run the swell packer on blank pipe and placed it at desired depth in the open hole, later run upper completions and sting into the top packer of lower completion. This way, we were able to inject gas into the lower part of reservoir Unit-G only, whereas the upper part was remained isolated completely. Using this technique saved company additional 2 million and extra time for re-horizontalization.