NUGGETS Gas Field: Pushing the Operational Barriers
- Pratik Saha (Total E&P UK Limited) | John Abolarin (Total E&P UK Limited) | Ali Parsa (Total E&P UK Limited)
- Document ID
- Society of Petroleum Engineers
- SPE Production & Operations
- Publication Date
- August 2014
- Document Type
- Journal Paper
- 162 - 171
- 2014.Society of Petroleum Engineers
- 4.6 Natural Gas, 3.4.1 Inhibition and Remediation of Hydrates, Scale, Paraffin / Wax and Asphaltene, 4.3.1 Hydrates, 4.3 Flow Assurance, 4.1.2 Separation and Treating
- hydrates, flow assurance, field management
- 4 in the last 30 days
- 228 since 2007
- Show more detail
- View rights & permissions
|SPE Member Price:||USD 10.00|
|SPE Non-Member Price:||USD 30.00|
The Northern Underwater Gas Gathering, Export, and Treatment System (NUGGETS) subsea development in the northern North Sea consists of five gas wells and a 40- to 70-km tieback to the Alwyn platform, with first gas in 2001 and peak gas production of 6 million std m3/d in 2004. Project life was expected to be 10 years, with the main constraints being methanol (MeOH) requirements for hydrate management and sealine minimum turndown. Because of increasing water production, the wells were shut in one after another, and the field was scheduled to be decommissioned in 2010. At that time, minimum recommended MeOH concentration was approximately 28% (wt/wt; MeOH/water), which allowed for a maximum water production of 40 std m3/d. Because of a concerted effort to keep gas rates at targets that respected all constraints and to reduce MeOH use to zero, an additional 4.0 million BOE has been produced from NUGGETS. This represents an incremental recovery of about 3.0%. In addition, the field life has been extended, with the possibility of further prospects being tied into the existing facilities. With MeOH constraints removed, the new issues became subsea-system-life longevity and reservoir management. Current field-operations philosophy is optimized to respect the minimum gas rate per well with or without water production. It is also aimed to manage water coning in the reservoir. The reservoir has very high permeability with kv/kh ≈ 1 and strong aquifer influx. Moreover, numerical and analytical methods were used to investigate the coning. This paper provides a critical assessment of the methods used from the flow-assurance, well-performance, and reservoir-management point of view. It concludes with a set of observations and recommendations for operators of dry-gas fields with strong aquifers and long subsea tiebacks.
|File Size||1 MB||Number of Pages||10|
GPSA. 2004. Dehydration. In GPSA Engineering Data Book (FPS), twelfth edition, Vol. II, Sec. 20. Tulsa, Oklahoma: Gas Processors Suppliers Association.
Hemmingsen, P.V., Li, X., and Kinnari, K. 2008. Hydrate Plugging Potential in Underinhibited Systems. Proc., 6th International Conference on Gas Hydrates (ICGH2008), Vancouver, British Columbia, Canada, 6-10 July,
Katz, D.L. 1959. Handbook of Natural Gas Engineering. New York: McGraw-Hill Higher Education.
Macpherson, C., Glenat, P., Mazloum, S. et. al. 2012. Successful Deployment of a Novel Hydrate Inhibition Monitoring System in a North Sea Gas Field UK. Presented at the 23rd International Oil Field Chemistry Symposium, Geilo, Norway, 18–21 March.
Sloan, E.D. Jr. and Koh, C.A. 2008. Clathrate Hydrates of Natural Gases, third edition, Vol. 119. Boca Raton, Florida: Chemical Industries, CRC Press.
Yang, J., Chapoy, A., Mazloum, S. et. al. 2011. A Novel Technique For Monitoring Hydrate Safety Margin. Proc., 7th International Conference on Gas Hydrates (ICGH 2011), Edinburgh, Scotland, UK, 17–21 July.