Well stimulation normally consists of matrix acidizing, acid fracturing and proppant fracturing. The optimum stimulation treatment depends on both reservoir characteristics and the formation damage mechanism. The oil recovery can be improved with successful stimulation treatments.

This paper presents a case study of a pilot stimulation project in the Onbysk oil field in Tatarstan, Russia. The objective of this project was to optimize stimulation treatments in geologically complex reservoirs for the improved oil recovery. The Onbysk field consists of seven stacked reservoirs with a complex lithology of shaly sandstone and limestone with microfractures. Different stimulation techniques have selective applications to different reservoirs for improved oil recovery. The improved oil recovery has been evaluated using production history data and decline technique.


Well stimulation is commonly used worldwide to increase well production rates. The main benefits, increased productivity and improved oil recovery, have been realized in many fields. The Onbysk oil field is located in Tatarstan, Russia near the city of Almetyevsk. The region's climate is moderately continental. The average temperatures are about 70 F in summer and 10 F in the winter. The extreme winter temperature may reach -31 F.

The Onbysk field was discovered in 1960. However, the development drilling started in 1985. The oil was claimed as "hard recovery oil". A number of matrix jobs and a few acid frac treatments were conducted before 1992 with mixed results due to the acid composition and the complex lithology.

A feasibility study of optimum stimulation was conducted by a major university in Texas, USA in 1992. Several possible formation damage mechanisms were identified. These included: damage from overbalanced drilling and poor completion practices, deposition of inorganic scales and organic damage due to paraffin depositions. The overbalanced drilling practices, combined with poor quality mud and overbalanced perforating with mud in the well, resulted in near wellbore damage. This indicated high skins should be expected. Therefore, production data was evaluated for a positive skin. The skin factor, k*h product and drainage radius were estimated by history match of production data using a reservoir simulator. Wells with positive skin factors were identified as requiring stimulation. Matrix acidizing, proppant fracturing and acid fracturing treatments were recommended for these seven stacked reservoirs with lithology changes from sandstone, donomized limestone, limestone, shaly sandstone, limestone and shaly sandstone. Limestone reservoirs showed secondary porosity due to the presence of natural fissures or micofractures. Most of the wells penetrated multiple reservoirs. The differences in reservoir characteristics and damage mechanisms indicated different stimulation techniques would be required to maximize stimulation results for improved oil recovery.

The pilot stimulation project was contracted to an American service company. Forty-five stimulation treatments were conducted in late 1993 and in 1994. These stimulation jobs included matrix acidizing proppant fracturing and acid fracturing treatments.

The production history before and after the stimulation was analyzed for production response time to the different type of stimulation treatments. Matrix acidizing and acid fracturing treatments cleaned up fast, but had mixed production results. Proppant fracture treatments took longer to reach a peak oil rate due to a longer cleanup time. The production decline technique was used to compute incremental oil and improved oil recovery.

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