High permeability hydraulic fracturing in Nimr cluster of oil fields within the Sultanate of Oman has been gaining momentum in recent years. This is despite of the inherent resistance towards deferring producing wells for a typically long intervention such as hydraulic fracturing. In part, that is due to the required pre fracturing preparation which ranges from removing low grade existing completion, removal of artificial lift pumps, installing fracturing completion, and finally post fracturing recompletion. This is in addition to damage presented by less-than-optimal fracturing fluids which may impair well productivity, especially in cases where oil is of moderate to high viscosity. Hence hydraulic fracturing of high permeability formations within Nimr fields dictated an optimal candidate selection process. This paper presents well-defined candidate selection criteria derived from regression modelling, in addition to design related optimizations such as the utilization of reduced gel loading designs and enhancing oxidizing breaker concentration for better cleanup and flowback. As part of the study within this paper, fracturing water injectors presented a less risky endeavor due to a shorter turnaround time from pre to post fracturing. It also presented an opportunity to enhance sweep efficiency in fields where water injectors are underperforming. Injector wells within the Nimr cluster of fields generally target high permeability formations (10-200 mD), however due to the quality of injected water and the degree of self-scaling due to temperature and pressure changes, skin build up is common. Hence the introduction of fracturing presented an efficient technique to bypass damage and generate larger conductive effective wellbore radii. This paper describes the restoration of several poorly performing producer and injectors that were treated between 2021 and 2022 using hydraulic fracturing. Injection results as well as post fracturing sweep efficiencies were compared to those prior to fracturing. These wells were also assessed in perspective of their injection patterns where results have shown substantial pressure support to nearby wells without fast-tracking water breakthrough. This resulted in the revival of some producer wells that were previously closed in due to poor aquifer pressure support.
Multidisciplinary data integration combined with the deployment of proper technology is key to optimizing shale gas completions. This paper focuses on the real-time completion optimization of multiple laterals drilled from the same well pad in shale gas reservoirs. These laterals are spaced as close as a few hundred feet laterally with varying vertical landing points. Though these laterals do expose more of the nanodarcy permeability shale rock and increase contact area through fracture stimulation-resulting in more efficient drainage-the challenge remains to optimize the stimulation treatment to maximize coverage around each designated lateral. The optimization process involves perforation and stage placement, sequential stimulation of these laterals, fluid and proppant schedules, treatment rates, and application of diversion technology when appropriate to achieve effective stimulation along these laterals and between the wells.In a comprehensive multiwell completion case history from the Barnett Shale, geologic, well, and surface seismic information was integrated with log measurements using Petrel reservoir modeling software. This integrated understanding was coupled with live microseismic data, enabling reliable real-time decisions during stimulation to optimize stimulation coverage and proppant placement around these laterals. Opportunities in making changes to original designs were seized when injectivity problems were encountered early in the treatment process. This approach was executed successfully to gain injectivity and, later, to increase the conductive fracture area, allowing the frac to be managed in real time.Observed fracture pressure responses and production from these pad wells validated the approach. Ultimately, an optimal horizontal stimulation was achieved by leveraging favorable rock properties to create a larger fracture surface contact area, thereby maximizing gas production potential and recovery.The integrated approach presented here can be applied to any single well or multilateral shale gas wells.
Hydraulic fracturing in oil wells within the Southern parts of the Sultanate of Oman has been considered a niche application until recently. This is due to high formation permeability which is a key differentiator of oil fields in the South compared to the North where hydraulic fracturing is more prevalent in tight gas fields. Yet recently, hydraulic fracturing has gained momentum in the South as it started becoming a major well completion technique to increase production while decreasing drawdown. In addition to growing interest in injector well fracturing to enhance overall injector well pattern performance. While hydraulic fracturing in high permeability formations has historically been attributed to damage bypass and creating a more conductive and a larger effective wellbore radius, it has been considered a risky endeavor in oil wells where post fracturing retained permeability may impair well potential especially in cases where oil is of moderate to high viscosity. Hence in Nimr fields, located Southern Oman, hydraulic fracturing of high permeability zones required a fit for purpose fracturing strategy that maintained good retained permeability at the targeted formation with minimal damage. This strategy included candidate selection using a pre-defined criterion derived from regression modelling, utilization of tip-screen-out designs, enhancing oxidizing breaker concentration for better cleanup and flowback, and optimal artificial lift pump designs to suit newly fracturing zones. In Nimr, several poorly performing producers and injectors were treated in 2021 using hydraulic fracturing after being assessed against a rigorous selection criterion. These included several water injectors. Production and injection results were compared to the initially estimated Folds of Increase (FOI) prior to interventions. All wells achieved the expected estimated gain using a pressure matched fracture geometry estimate. Hence this method has provided a basis for further design optimization to increase production yield. Results have also provided lessons learnt in artificial lift pump sizing and pump seating depth. Injector wells were also assessed in respect to their patterns where results have shown significant pressure support to nearby wells, which in some cases revived wells that were previously shut in due to poor pressure support. The success of hydraulic fracturing in high permeability wells in the South of Oman has driven the increase in frequency and magnitude of these otherwise niche interventions. Although further optimization in candidate selection and treatment designs are needed to ensure capital expenditure is justified by production gain.
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