Protect and Then Inject: Optimized Well Fluids Successfully Drill Depleted Reservoirs To Store Gas
- Stephen Vickers (Baker Hughes) | Stephen Bruce (Baker Hughes) | Alistair Hutton (Baker Hughes) | Paolo Nunzi (Eni)
- Document ID
- Society of Petroleum Engineers
- SPE Drilling & Completion
- Publication Date
- March 2012
- Document Type
- Journal Paper
- 113 - 117
- 2012. Society of Petroleum Engineers
- 5.4.2 Gas Injection Methods, 1.11 Drilling Fluids and Materials, 5.6.4 Drillstem/Well Testing, 1.6 Drilling Operations, 4.1.2 Separation and Treating
- Fluids, Gas Storage
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- 575 since 2007
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A major operator has initiated the data-acquisition campaign in the southern North Sea for a future storage facility capable of holding 5 billion m3 of gas. It is estimated this venture will double the existing gas supplies stored in the UK and represent more than 5% of its annual gas demand. As North Sea gas production decreases and the UK becomes more dependent on imports, the ability to store gas has become an important part of the UK energy policy.
Drilling into depleted reservoirs for gas storage produces several major technical problems and issues that must be addressed. This field is a pressure-depleted reservoir with a differential pressure equivalent to 7.3 lbm/gal between the drilling fluid's hydrostatic pressure and the reservoir pressure. This differential must be controlled to eliminate the risk of differential sticking, downhole losses, and hole collapse.
Because of the reservoir depletion, it would be impossible to backflow and clean up the near-wellbore region without a post-drill-in treatment fluid to remove the fluid filter cake and water-wet all the surfaces for gas injection. To ensure project success and usable fluid designs, reservoir conditions were simulated in the laboratory and fluid parameters were altered to provide the optimum properties to minimize the future risks.
The paper discusses in full the laboratory design process, the verification of the drill-in and treatment fluids as being fit-for-purpose, and their successful application in the field. Initial well testing suggested that the expected injection rates of 500 scf/min at 300 psi were exceeded, with rates of 750 scf/min at 280 psi reported.
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