Unit R is a tight carbonate reservoir onshore Abu Dhabi currently undergoing redevelopment with the aim to substantially improve the ultimate recovery factor. Better pressure support is required to increase the production. To this end, two water injectors were drilled in tight areas where wells suffer from low injectivity index and high well head injection pressure (WHIP). Reaching the expected injection rates therefore required very aggressive matrix-acid stimulation techniques. Acid wash is a common stimulation practice for medium-high permeability wells in ADNOC when the purpose is merely to remove drilling damage without creating large negative skins. For low permeability reservoirs such as Unit R, more aggressive stimulation techniques are needed to deliver the expected production and injection target rates. We tested two such methods; Well A1 was treated using Abrasive Jetting (JA), which is conveyed by coiled tubing whereas in Well A2, we deployed a Smart Liner (SL) where acid can be bullheaded at high rate from surface. In Well A1, the Abrasive Jet CTU in Open Hole doubled the injectivity index. However, the Injection Logging Test (ILT) revealed an uneven injection profile along the horizontal section (more injection in the better properties zone). In well A2, Smart Liner bull-head acid stimulation was able to triple the injectivity index. The ILT shown an even injection profile across the horizontal section, actually slightly more in areas with poor rock properties due to a large number of holes in those intervals. The cost of the Abrasive Jet is 40% less than the Smart Liner stimulation but the latter has more medium/long term advantages: Even injection along horizontal section (improving sweep efficiency) Ensure 100% accessibility to the well (avoiding formation collapse issue) Stimulation from surface, no need CTU (saving cost), useful for potential future re-stimulations. After only 10 months of injection the reservoir pressure has increased 50-100 psi in surrounding nearby oil producers, resulting in 20% more oil while honoring all operational guidelines. It is quite exceptional to be able to assess with real data the effectiveness of two different stimulation techniques. The two pilot wells have same horizontal length, almost same rock properties, and are drilled parallel to each other. Both Smart Liner and abrasive jetting substantially improve water injectivity but the more uniform flow profile observed in the Smart Liner is a distinct advantage when selecting an appropriate completion-stimulation design for future water injectors.

The sector screening review is a surveillance tool used to assess and find opportunities to increase the oil production and improve the performance of the reservoir. We developed a novel interdisciplinary workflow (geology-engineering) integrating dynamic and static data in order to generate opportunities at well and field level; this methodology was used to analyze the impact of fractures in the reservoir performance and management. The complexity of the geology on areas near a graben system (structure at center of the field with biggest vertical displacement) was suspected to cause flow anomalies that ultimately affected the well productivity indexes. After an exhaustive evaluation, it was noticed that a well showed lower productivity index (PI), 2-3 times less than nearby producers in the area, same reservoir Unit Z2 (similar lengths, conditions). To understand the root cause of such performance, a geoengineering workflow was implemented, integrating pressure transient analyses (PTA), production logging (PLT), bottom hole image (BHI), seismic (exceptionally complete dataset) and extrapolated to other wells with similar behavior. The PLT showed that 70% of the well contribution was concentrated in only a small interval of the horizontal section, this interval was correlated to a conductive fault through BHI, which was also detected by seismic (correlates with low velocity anomaly). The PTA showed unexpected pressure transient behavior suspected to be related to the dynamic effect of the fault and associated fractures. Learnings from above analyses triggered actions in different scales/stages: at Well scale, 1st Stage: the well was selected to be completed using selective stimulation with abrasive jet, to remove damage of the first 400 ft. of the well (skin factor masked by fracture contribution) and unlock the potential of non-contributing zone (after fault, to toe); allowing the well to produce 25% additional oil and doubling the PI. 2nd Stage (planned): workover proposal to install lower completion (LC), to ensure even depletion, avoid by-passed oil and prevent early water/gas breakthrough. Field scale: new wells to be drilled in reservoir zones potentially affected by the graben will be equipped with LC. Finally, a geological well testing framework matching the PBU and PLT was implemented based on a high resolution geological model designed to capture the properties of the matrix and fractures. The results from this study were used as diagnostic tool for additional wells with similar conditions which lack PLT data. Noticeably, the presence of flow controlling fractures was usually suspected but not properly assessed/quantified in this reservoir, mainly due to the fact that the dynamic impact of these fractures was masked by the overlapping of different geological phenomena. The implementation of our geological-engineering workflow allowed immediately triggering actions that could lead to major performance enhancements at field- and well-level, including field development, management and modelling practices in such complex geological arquitectures.

Objectives/Scope One of the reservoir units producing from a carbonate reservoir in Abu Dhabi field since 1980 is characterized by having relatively good rock quality to the South with deterioration in rock quality towards North. Inverted nine spot gas injection pattern started for this unit since 1992. Despite all the efforts to improve the recovery from this reservoir unit, still the recovery factor after 40 years of production did not exceed 15 %. This is in addition to the inability of the unit to sustain its production target. Methods, Procedures, Process A novel mixed pattern gas and water injection scheme proposed to improve this reservoir unit recovery. First, replace the existing gas injectors by water and add new water injectors in good-quality area to ensure good water injectivity. Second, reduce gas injection or add new gas injectors if needed in the poor-quality area to keep a minimum VRR of one splitting equally between water and gas injection. We developed a novel line drive pattern approach for locating the new water and gas injectors which we call it "Produce Shallow and Inject Water Deep (PSIWD)" for water injectors and "Produce Deep and Inject Gas Shallow (PDIGS)" for gas injectors. All the injectors are horizontal to imitate bottom aquifer for PSIWD in the good-quality area and gas cap for PDIGS in the poor area. Similarly, all the producers are horizontal located at the top of the reservoir in the good-quality area and at the bottom in the poor-quality area to reduce the water and gas early breakthrough. Results, Observations, Conclusions This approach simulated on a full field scale and proved its efficiency in increasing the recovery factor to 40 % and maintaining longer plateau for 18 years. On top of this, it is economically promising by reducing the OPEX for gas injection to 1.2 Billion USD savings that can reach to 2.4 Billion USD savings in the next 30 years with the application of full water injection (PSIWD) in both good and poor-quality areas. Novel/Additive Information Unlike the conventional line drive pattern with injecting and producing within the oil column, our proposed mixed line drive pattern water and gas injection with the application of PSIWD in the good-quality area and PDIGS in the poor-quality area has tendency to reduce the gas and water breakthrough thus ensure better sweep efficiency and higher pressure support. On top of this, the proposed development approach shows 40 % reduction in the cost per barrel compared to the current development approach due mainly to the OPEX reduction for the gas injection and the incremental increase in recovery.