Abstract
Ecuador is producing oil today from mature fields with increasing water cut, and most of the reservoirs are subhydrostatic with permeability ranging from 10 to 1000 md and significant clay content (mainly kaolinite and glauconite) in the formation matrix. As a consequence of the increasing workover interventions and fluid invasion due to the depleted reservoir conditions, there was need to stimulate the wells to be able to bypass the damage zone. In the past, it was common to lose completion fluid into the reservoir, resulting in a 20% to 50% reduction in production or even in extreme cases killing the well when the completion fluid was incompatible with either reservoir fluids or formation clays.
Historically matrix acidizing treatments have been perfomed in an attempt to remove formation damage or to increment production, with limited success. Matrix acidizing treatments are not sufficient to fully remove the damage because of the high clay content, and in many cases, the damage cannot be removed by just treating the critical matrix. Conventional hydraulic fracturing treatments were then tried as a means to bypass the damage. However, some of the wells treated showed positive skin factors following the fracture treatments.
The wells in which hydraulic fracturing had proved unsuccessful were studied in more detail to understand the reason why hydraulic fracturing resulted in a positive skin. It was concluded from the formation mineralogy and core flow testing that the fracturing treatments were unsuccessful due to a reduction in the formation permeability due to the mechanical plugging and movement of the kaolinite or disrupted mica in the pore throats. The reduction in the matrix permeability results in skin damage in the faces of the fracture. The fracture-face damage or skin can also be caused by fluid loss from the fracturing fluid through the fracture faces, which creates an additional drop in pressure that may further reduce the productivity of the well. The impact of these effects on the productivity of a treated well depends on the reservoir characteristics and mineralogy, fracture geometry, extent of fluid leakoff into the reservoir, and the viscosity of the fracturing fluid filtrate. The magnitude of these effects and resulting additional pressure drop generally increases with increasing reservoir permeability.
To eliminate or mitigate the fracture-face skin effect in water-sensitive formations, a new treatment incorporating a prepad of a viscosified blend of chelants and acid was field tested. By adding this stage into the fracturing treatment design, the retained matrix permeability was increased to +/- 70% of the undamaged matrix permeability, resulting in negligible fracture-face skin. The productivity of fracturing treatments performed using this innovative technique resulted in negative skin factors and production ratios that exceeded expectations in water-sensitive and high clay content reservoirs.
