Iron Sulfide Scale Management in High-H2S and -CO2 Carbonate Reservoirs
- Giulia Verri (Heriot-Watt University) | Ken S. Sorbie (Heriot-Watt University) | Michael A. Singleton (Heriot-Watt University) | Charles Hinrichsen (Chevron) | Qiwei Wang (Saudi Aramco) | Frank F. Chang (Saudi Aramco) | Sunder Ramachandran (Saudi Aramco)
- Document ID
- Society of Petroleum Engineers
- SPE Production & Operations
- Publication Date
- August 2017
- Document Type
- Journal Paper
- 305 - 313
- 2017.Society of Petroleum Engineers
- Partitioning, Carbonate reservoir, Iron sulphide, H2S, Iron sulfide
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- 342 since 2007
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Combined sulfide/carbonate-scale formation in wells producing from reservoirs with high carbon dioxide (CO2) and high hydrogen sulfide (H2S) represents a serious threat to production efficiency and system integrity. Understanding of both the main source of iron that forms the iron sulfide (FeS) scale and the phase partitioning and effect of the acid gases (CO2 and H2S) is important in devising and implementing the correct sulfide-scale-control program.
In this paper, a pressure/volume/temperature (PVT) software package was used to take production data and model water condensation/evaporation and calculate gas compositional changes and CO2/H2S partitioning between the liquid phases. This enabled reservoir-fluid compositions to be predicted by use of an in-house scale-prediction software, with particular focus on the stable concentration of iron in the aqueous phase. A sensitivity study was then performed to assess the parameters that impact iron solubility within the reservoir. With the reservoir-fluid compositions established, changes along the production stream (over a given range of temperatures and pressures) were determined and used to predict scale formation at those conditions. A modeling workflow was developed and tested against field data for the prediction of sulfide/carbonate-scale deposition in gas wells producing from carbonate reservoirs. The workflow was then applied to a number of gas wells in the Middle East that produce 2 to 4% CO2 and 2 to 6% H2S. By understanding changes in flow rate, gas partitioning, and fluid composition along the production stream, it was possible to map the potential scale deposition through the system and to compare these results with scale deposits observed in the field. It was calculated that the pH in the wellbore is low and mainly determined by the partial pressure of CO2, while the pH in the reservoir is higher because of the presence of calcium carbonate (CaCO3). Therefore, it was possible to determine that dissolved iron is highly unlikely to be present in the formation fluids, thus leading to the conclusion that the source of iron from which FeS deposition occurs must be the result of sour corrosion. In addition, the resulting likely profiles of FeS deposition were predicted.
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