Maersk Oil Kazakhstan Gmbh assumed operation of the Dunga field in 2002. To increase production from the existing wells, a new pinpoint hydrajetting stimulation technique was introduced to Kazakhstan in 2005 with the successful hydraulic fracturing of a horizontal well in the onshore Dunga oil field. This paper presents a case history describing the second application of hydraulic fracturing of a horizontal well in the Dunga Field, but the first one where multiple hydraulic fractures were performed in a lateral that was completed with a slotted liner, without requiring isolation between the individual fractures. To induce multiple hydraulic fractures from his type of completion a "pinpoint" hydrajetting stimulation technique was used.

In this paper we will review the operational challenges encountered during the multi-stage fracturing treatments and discuss the pressure responses observed during treatments. Operational challenges included placement of 5 individual fractures along the horizontal slotted liner, surface fluid handling, and downhole tool issues. Several challenges were overcome during well preparation and in tailoring the pinpoint hydrajetting technique for the specific well that was stimulated.

This paper will first document how the technical and operational challenges were managed during the well workover and stimulation campaign. The later part will review the well's production data and post-frac matching of the well pressure history with simulation from initial completion through more than 12 months of post-frac production.


The Dunga Field has been developed primarily with vertical wells but also 6 short horizontal wells were drilled. The vertical wells had been completed conventionally with cemented casing and then perforated. One of the vertical wells had been fracture stimulated with a resulting good production response. However, the fractured well was considered to be in the very best area of the field and fracture stimulation of additional wells had not been attempted. The horizontal wells were completed with openhole/slotted liner completions. All wells in the field require artificial lift. This had been done using beam pump units.

In 2004, one new vertical well was drilled for water injection and reservoir monitoring purposes and two new horizontal wells were drilled. One of the horizontals, Dunga-35 was completed as an open hole multilateral, however the production results of the well identified that formation collapse might be an issue, at least in some sections of the reservoir. The other horizontal well, Dunga-34 was drilled with a single lateral of approximately 6,670 ft which was completed with a 7-inch cemented liner. The horizontal section was completed on 9 intervals being individually fracture stimulated. Mechanical isolation was achieved using the PSI completion technology (Damgaard et al. 1992) which involved completion of the individual zones with a section of 4.5" tubing with a seal stack, a sliding sleeve and a packer. The sliding sleeves were opened and closed using coiled tubing. There was one additional zone planned for this well but could not be fracture stimulated due to operational or formation issues. This well produced as the best well in the history of the field, but analysis indicated the Dunga field may need a lower cost completion method for most future wells to provide adequate economic returns.

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