The deposition of scale in the near-well formation and production string can result in a significant decrease in well productivity. Properly designed scale inhibitor squeezes can successfully prevent scale deposition and extend well performance. Even though most wells in the Tengiz field produce virtually water free oil (less than 1% watercut (WC)), inorganic scales have been observed in many of these wells. Frequent acid stimulations are required to maintain the optimum well performance. An extensive research project was initiated to reduce the need for frequent acid treatments and still maintain well deliverability at sustained rates. To identify an effective scale inhibitor product, inhibitor-brine compatibility testing and dynamic tube-blocking performance testing were conducted. Field application of the selected inhibitor in both low and high rate wells has verified the effectiveness of the squeezes. Treatment with the scale inhibitor attained sustainable well productivity and delayed the need for subsequent acid stimulation treatments. This paper will share the best practices in scale inhibitor design, inhibitor selection, identification of well candidates, the execution and post treatment surveillance stages. Case studies shown to illustrate the performance of scale inhibitor squeezes in Tengiz.

Tengiz is a unique, super-giant oil field located in western Kazakhstan that is characterized as a fractured carbonate reservoir with high concentrations of H2S. It is operated by TengizChevroil (TCO). Current production is ~ 530,000 BOPD from 70 active producing wells. As part of an effort to increase the field's production output, a workover and stimulation program was initiated in 2011 after a hiatus of more than five years from such activities. A sizeable part of this workover effort was a matrix acid stimulation program which took lessons learned from earlier acid stimulation campaigns in the Tengiz Field to develop a modified acid stimulation treatment design. The result of this most recent program was a significant and sustained response in well productivity. The key components of the 2011/2012 acidizing program include: 1) increased acid volumes ranging from 50-100 gal/ft and 2) an acid diversion system that included the use of a viscoelastic diversion acid and degradable fibers. Another factor that supported the success of the acid stimulation program was the involvement of a multi-disciplinary team that addressed both candidate selection and acid stimulation design. The TCO 2011/2012 Acid Program has shown incremental improvement in all 19 wells stimulated to date. The average initial incremental gain following stimulation is ~4, 240 BOPD per well and the overall improvement in the Productivity Index (PI) has more than tripled. Post-stimulation production logs have confirmed improvement in the production profiles, indicating the acid diversion methods are having a positive impact.

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The team evaluated multiple options for conformance control, with the primary focus on shutting off water. The team broadened the focus to include gas shut off, as well as implementation in the sour gas injection wells, and the water injection wells. The new completions have become the preferred completion for most of the wells. The conformance control packer assembly is selected based on the openhole caliper logs, pressure measurements, drilling breaks, fluid saturations and the thickness of the reservoir intervals. After the drilling rig runs the completion, the wells are completed with a coiled tubing unit. The coiled tubing tools and procedures have improved since the initial swell packer completions. Many of the new wells use smart coil with embedded fiber optic cable to help ensure a successful completion. The swell packer completions have been very successful as a whole, but not every swell packer is effective in isolating between layers. The Distributed Temperature Sensing (DTS) has been very useful in identifying both leaking packers, as well as communication between zones from within the reservoir. There are several benefits of using the swell packers for mechanical diversion of stimulation fluids. Without the swell packer completions, the average treated zone was 500m thick. Initially, most conformance control completions consisted of three to four packers. Since then the average number of packers has increased to five to six packers per well. Most stimulation treatments now target an interval of less than 100m. There have been several major rig workovers (MRWO) in the sour gas injection area of the field. Comparisons pre and post MRWO well performance indicate that the swell packer improved the productivity of wells. This paper shows how the swell packer completions have helped to reduce unwanted fluids and enhanced the oil production capability of the wells. It will describe the selection process for packer placement, and the success rate of these packers. The paper also covers the evolution of the coiled tubing procedures that helped to make the conformance control program a success.