Wax Deposition in North Sea Gas Condensate and Oil Systems: Comparison Between Operational Experience and Model Prediction

2002 ◽  
Author(s):  
Catherine Labes-Carrier ◽  
Hans Petter Rønningsen ◽  
Johnny Kolnes ◽  
Emile Leporcher
Keyword(s):  
North Sea ◽  
Model Prediction ◽  
Gas Condensate ◽  
Operational Experience ◽  
Wax Deposition

Identifying Optimal Pigging Frequency for Oil Pipelines Subject to Non-Uniform Wax Deposition Distribution

2014 ◽  
Author(s):  
Wenda Wang ◽  
Qiyu Huang ◽  
Si Li ◽  
Changhui Wang ◽  
Xi Wang
Keyword(s):  
Pressure Drop ◽  
Model Prediction ◽  
Extreme Case ◽  
Wax Deposition ◽  
Deposition Model ◽  
Oil Pipelines ◽  
Pump Stations ◽  
The Cost

Wax deposition in oil pipelines causes reduced throughput and other associated problems. Periodical pigging program can effectively minimize the cost of wax deposition. This paper shows a typical pigging case study for a field pipeline subject to non-uniform wax deposition distribution by using a developed wax deposition model. The model prediction results prove that the wax is distributed in a short, localized accumulation along the first half pipeline. The resultant pressure drop along the pipeline was examined to reveal the effects of non-uniform wax deposition distribution on the pipeline production. In extreme case, the pressure drop of severe localized section increases by 50%, while this value between pump stations is merely 3%. A maximum wax thickness of 2–4 mm is used as a criterion to determine an optimal pigging frequency. The case study pipeline is recommended to be pigged at a frequency of 10 to 15 days, using by-pass pigs.

Dynamic Flexible Riser Ancillary Equipment—North Sea Asset Integrity Management Experience and Lessons Learned

2020 ◽  
Vol 143 (3) ◽  
Author(s):  
Damir Tadjiev
Keyword(s):  
Case Studies ◽  
North Sea ◽  
Oil And Gas ◽  
Lessons Learned ◽  
Operational Experience ◽  
Flexible Riser ◽  
Remotely Operated Vehicle ◽  
Integrity Management ◽  
Flexible Risers ◽  
Ancillary Equipment

Abstract Dynamic flexible risers are complex engineered systems, which provide a connection between topside (normally floating) facilities and subsea pipeline infrastructure on offshore oilfields. Such systems require the use of ancillary equipment to ensure the riser’s correct configuration is maintained throughout the service life. Industry experience shows that the integrity management of riser ancillary equipment is not always comprehensive, and failure of such equipment is one of the causes of premature removal of flexible risers from service. This article presents some case studies from the operational experience of dynamic flexible risers by an operator in the UK North Sea covering a period of approximately 20 years. The case studies look at the anomalies identified in service by general visual inspection (GVI) using a remotely operated vehicle (ROV) and the lessons learned. Some of the anomalies, had they not been identified and addressed promptly, could have resulted in costly repairs, which demonstrates the importance of inspecting the ancillary equipment of flexible risers as a part of the riser integrity management strategy. The challenges associated with integrity management of ancillary equipment of dynamic flexible risers are also discussed. The case studies presented in this article demonstrate that ROV GVI is an effective method for identifying installation and in-service anomalies related to flexible riser ancillary equipment. The purpose of this article is to share lessons learned with the wider offshore oil and gas community. It is also believed that the information presented in this article may provide useful information to other users of dynamic flexible riser systems when developing and/or implementing their subsea pipelines integrity management programs.

The Lomond Field, Block 23/21, UK North Sea

2020 ◽  
Vol 52 (1) ◽  
pp. 511-522 ◽  
Author(s):  
Srmuti Jena ◽  
David Olowoleru
Keyword(s):  
Continental Shelf ◽  
North Sea ◽  
Gas Condensate ◽  
Recovery Factor ◽  
High Recovery ◽  
Integrated Production ◽  
Production Platform ◽  
Production Wells ◽  
Production History ◽  
Very High

AbstractLomond is a gas–condensate field on the east flank of the Central Graben UK Continental Shelf, some 230 km east of Aberdeen in Block 23/21. The field was discovered in 1972 and was developed with nine production wells from an integrated production platform. Lomond is a large salt-induced anticline with four-way dip closure. The reservoir comprises Paleocene turbidite sandstones with the majority of the hydrocarbon volume in the Forties Sandstone Member and the top seal is provided by laterally extensive mudstones of the Sele Formation. The field is structurally compartmentalized with three different hydrocarbon–water contacts, but with the gas leg in pressure communication. Significant reservoir and structural complexities are observed in Lomond Field; however, the production behaviour exhibits classical tank-like depletion behaviour over its production history. With a very high recovery factor to date, the field has produced 883 bcf or 86% of the gas resource initially in place.

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