This article describes the application of relatively high-density foamed cement for cementing wells in the Volga and Urals region. Good cementing practices with high density or conventional density cement slurry is required to ensure mud displacement in fluid saturated intervals of reservoir formations (Benge et al; 1982). With this requirement met, the cement column should circumferentially cover the annulus at this very interval which is exposed to the highest loads. However, due to limited physical and mechanical properties of conventional cement slurries in both liquid and solid state, in certain cases conventional slurries do not solve the problems encountered by the Customer, namely elimination of annular flow between the casing and cement sheath. High-density foamed cement is considered as an improved alternative to conventional cement slurries, and results in a high quality and durable sealing of gas and oil saturated production zones for the life of the well. Proprietary software and process equipment are used for the mixing of the foamed cement slurry with a variety of foaming properties. This process enables the use of a base cement slurry with higher density (up to 2.1 g/cm3) for delivering foamed cement slurries in a wide range of densities. To avoid possible cross flows behind the casing, pilot tests were conducted, where a conventional cement slurry (1.80–1.90 g/cm3) was replaced with a high-density foamed cement slurry with equivalent density with a foam quality of approx. 10% making the cement sheath elastic with improved adhesion to both the casing string and the formation (Spaulding et al; 2018). Pilot tests, incorporating the cementing of several production casings, were conducted where only foamed cement slurries with various foam quality were used in the entire cementing interval. No conventional (non-foamed) cement systems were used in these cases.

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This document describes the integrated engineering approach and technical solution used to perform a construction project of the first wildcat well in Khatanga subsoil area of the Laptev Sea. Because of the small scope of performed geological exploration works and the absence of any previously drilled wells within the target area, a low degree of geological knowledge existed for this project. The unique location of the license area eventually complicated the profile of the Centralno-Olginskaya 1PO wildcat well and the logistics on the peninsula, consequently affecting the planning and performance of the project. In these conditions, RN-Shelf-Arktika OOO and Halliburton encountered a range of challenging tasks associated with high quality planning and safe performance of the expected work scope within the planned timeframes. Other challenges encountered included fulfilling all geological tasks required to reduce expenses and developing technological and organization solutions for the subsequent construction of wells and the discovery of a new oilfield in the Eastern Arctic. Because of the low level of geological knowledge about the territory, the operator regularly assigned new geological tasks. These changes eventually resulted in a longer wellbore (5530 m, rather than 4200 m), increased scope of geological activities (a longer coring interval of 156 m, rather than 90 m), and well design changes (five casing strings, rather than four). To ensure the fulfillment of the required tasks, the completion of the project was based on an integrated approach for the integrity of the proposed technological and organization solutions, high quality of planning, and risk management and application of advanced technologies. This approach ensured 100% fulfillment of the geological objectives within the established timeframes and helped to develop a map of lessons learned with recommendations to optimize time and costs in the construction of future wells at the new field. Because of the project remoteness and challenging climate conditions, the well construction cost is the key factor for efficient field development (Lebedeva et al. 2017).