Abstract

Petroleum Development Oman (PDO) is drilling sour reservoir wells in the south of Oman. The challenge for these wells is that the completions are suffering from an iron sulfide scale formation during the production stage. Iron sulfide scale precipitation occurs from the reaction of hydrogen sulfide (H2S) and iron oxide (hematite or other metals oxides). The latter is usually used in the high density conventional cement slurries to cement the liner across the reservoir intervals. The iron sulfide scaling on these wells reduces the internal diameter of the liner and the tubing. The consequence of this is the restriction of access to the wells with surveillance equipment for data acquisition (for example production logging) and other tools. A new solution was found to eliminate the formation of the iron sulfide scaling in future wells. This solution is the implementation of an innovative optimized particle size distribution cement system, with low water content and high mechanical performance, that meets the well design requirement. The cement slurry formulation contains no iron and hence meets the cement system specifications. Extensive laboratory work was undertaken to engineer the slurry to the required specifications and yard trials were also performed. PDO and Schlumberger have worked very closely and have been able to execute the first ever metal-free cement system for such environments. This paper will cover the long term zonal isolation challenges that wells, with the risks of iron sulfide scaling, are facing. New technologies and techniques used to seal and cement these wells will be presented with case studies from well operations.

Background

The field N is a high profile field was discovered by exploration well A-1 in 1989. It is situated 40 km west of the NM field and 60 km north of the MM field in the South Sultanate of Oman salt basin in an area where no infrastructure was present at the time of discovery. To date thirty vertical wells, including one 4 hole multi-lateral, have been drilled in field N. The field contains the unique Athel silicilyte formation, some 4.5 km below the surface. The Athel reservoir has a gross thickness of up to 400 m and is fully encased in sealing salt as a result of which the reservoir is geo pressured to 80 MPa. Whilst porosity (23 Pu), net-to-gross (>90%) and oil saturation (˜80 su) are favorable in field N, the permeability is extremely low. This is due to the fact that the rock consists mainly of micro-crystalline silica with a uniform size of around 2–3 µm, which leads to extremely small pores and pore throats. The oil in field N is very light and volatile. It has a density of 0.622 g/cm3 at reservoir conditions, with a solution GOR of 410 sm3/m3 and a bubble point pressure of 11600 psi, resulting in an API gravity of 48 at stock tank conditions. The oil is also sour, containing 1.5 mol% H2S and 3 mol% CO2, no formation water and under 1 %, by volume, water of condensation. Through special PVT experiments the oil has been shown to be miscible with hydrocarbon gas down to pressures close to the bubble point pressure. Miscible gas flooding was therefore identified as a potentially attractive EOR development. Field N wells are faced with the following related challenges:

  • Deep reservoir sections (up to 4,500m);

  • Very high reservoir pressures (± 11600 psi);

  • Sour & Corrosive Reservoir fluids

In addition, recent experience shows that hematite present in the cement slurry is an issue and needs to be addressed.

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