Fracture Optimization Reduces Completion Cost while Improving Well Productivity in the Valdemar Field Offshore Denmark
Authors: Stemberger Dario , Saldungaray Pedro , Palisch Terry 
Published: October 2014

The Valdemar Field is located in the Danish North Sea sector with the target reservoir being a Lower Cretaceous "dirty chalk" containing up to 25% insoluble fines, &gt;20% porosity and permeability below 0.5 mD. The formation will not produce commercial quantities of oil without stimulation and it has been shown through laboratory core experiments as well as field trials that acid fracturing does not maintain conductivity as effectively as propped fractures. The initial reservoir pressure is above seawater hydrostatic and the reservoir thickness ranges from ten to several hundred feet. The Lower Cretaceous Chalk is found below the typical Ekofisk and Tor formations, which have been the target horizon in the North Sea for over four decades. Valdemar has been successfully developed with extended reach horizontal wells but, in order to establish economic production rates, all wells must be stimulated as part of the initial completion. In a typical Valdemar well, a 16,000 ft long lateral is drilled, with the toe of the well completed with a limited entry, predrilled liner, while the upper 10,000 ft of lateral, which is within coiled tubing reach, is completed with 12 - 14 propped fracture stages. Traditional designs revolved around placing 500,000 to 1,000,000 lb of 20/40 natural sand per stage. Consequently, very large volumes of proppant had to be handled during the completion, creating a logistics challenge, more so in an offshore environment where proppant available on location is limited to the capacity of the stimulation vessel.

Stimulations on several wells showed suboptimal production rates which led to the conclusion that the Lower Cretaceous was not economically producible. An intensive study was carried out to evaluate all aspects of the fracture design and implementation which resulted in 11 key findings comprising pumping schedule, fracture fluid design, proppant selection and flowback control, completion hardware, QA/QC during the fracture execution and well cleanup, data acquisition for real-time monitoring and "after-closure" analysis. This paper focuses on the aspects of proppant selection and adequate fracture conductivity placement, with the goal of improving well productivity and cumulative recovery. Reservoir simulation advised that replacing natural sand by a larger, lightweight ceramic proppant could result in reducing proppant volumes by up to 50% while improving productivity by 20 to 50%. By reducing the proppant volume, the stimulation vessel port calls to load materials for multistage treatments could potentially be reduced resulting in significant savings. This was deemed a critical factor for future offshore multistage fracture completions which could benefit significantly from reduced roundtrips in terms of time, cost and early production.

The recommendations of the optimization program were implemented in two wells. PLT results confirmed the predictions, that despite the total proppant volume being cut by 50%, the zonal contribution of the ceramic stimulated zones was better than that of natural sand in all cases. The higher fracture conductivity obtained with the ceramic proppant, even using one half the sand mass, resulted in improved productivity by some 50%. These completion optimization measures allowed for the successful development in the flank wells that might have otherwise been deemed uneconomic.