Ultradeep, ultrahigh-pressure wells in the Julia Field, Gulf of Mexico, are completed using multi-zone hydraulic fracturing treatments to optimize production from Wilcox Formation turbidites while mitigating risk of sand production to the surface. Despite deployment of an advanced superhigh-strength ceramic proppant system specifically engineered for extreme closure stress environments one of the wells experienced a sudden jump in average skin factor most likely related to progressive degradation of the fracture treatment due to high pace drawdown. In order to assist in answering important questions related to the potential for triggering further detrimental flow impairment with continued pressure decline, we have developed novel geomechanics testing techniques to quantify the development of both choke and fracture face skin effects as a function of increasing closure stress. These laboratory results provide useful data on the potential magnitudes of conductivity losses and interface damage to be expected with continued production and important insights into the likely micromechanisms involved.


The Julia deepwater oilfield is located approximately 426km (265 miles) southwest of New Orleans (Fig. 1) in the Gulf of Mexico (GoM) in water depths of more than 2,100m (7,000ft or 1.3miles) and utilizes subsea pumps that have one of the deepest applications and highest operating pressures in the industry to achieve a design capacity of 34,000barrels per day for an estimated lifespan of 30years. Reservoir consists of Upper (or Late) Paleocene to Lower (or Early) Eocene age, Wilcox Formation siliciclastic fan turbidites. The Lower Tertiary deepwater GoM Wilcox trend generally comprises a predominantly Louann “mother” salt basin with salt-cored anticlinal closures, associated specifically with salt pillow structures in Walker Ridge (

Meyer , 2007; Oletu , 2013


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