ESP Operational Challenges in Complex Mature Oilfield in the North Sea
- Edna Michelle Bisso Bi Mba (Wintershall Dea) | Göktug Diker (Wintershall Dea) | Andree Frohberg (Wintershall Dea)
- Document ID
- Society of Petroleum Engineers
- SPE Europec featured at 82nd EAGE Conference and Exhibition, 8-11 December, Amsterdam, The Netherlands
- Publication Date
- Document Type
- Conference Paper
- 2020. Society of Petroleum Engineers
- 2.1.3 Completion Equipment, 4.2 Pipelines, Flowlines and Risers, 5 Reservoir Desciption & Dynamics, 3.1 Artificial Lift Systems, 2 Well completion, 5.6.5 Tracers, 2.2 Installation and Completion Operations, 4.3.3 Aspaltenes, 5.6 Formation Evaluation & Management, 3.1.2 Electric Submersible Pumps, 1.8 Formation Damage, 3 Production and Well Operations, 1.8 Formation Damage
- Reservoir pressure maintenance, ESP performance, Well production optimization, Asphaltene deposition, Water injection
- 21 in the last 30 days
- 21 since 2007
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In this paper, the well under consideration is a horizontal oil production well located in the northern part of the Mittelplate oilfield, Germany’s largest oilfield. The well production started in July 2017 via electrical submersible pump (ESP) at an average initial liquid rate of 115 m³/d with no water production. One year after production start, the ESP performance decreased resulting to a significant drop in oil production. Since then, the well has been operated as an intermittent producer to prevent severe damages at the ESP. The objective of this study is to describe the different measures carried out to restore well productivity and present results achieved. Based on previous field experiences, it was assumed that the ESP performance reduction was due to asphaltene precipitations in the pump. The well was therefore regularly treated with aromatic washouts to dissolve asphaltene depositions. An attempt to achieve a more suitable and cost-effective alternative to the aromatic washouts was tested with asphaltene dispersant injection through the chemical injection line (CIL) of the well. After several months of field test, the aromatic washouts as well as dispersant injection could not improve the well performance. An additional measure to increase well productivity was to support the reservoir pressure in the northern part of the reservoir. This was implemented in late 2018 whereby, a nearby production well was converted into an injection well with a steady increase in injection rate. Increased bottom hole flowing pressures are being observed currently at production wells. However, it is challenging to evaluate the effect of the injection at the target well without downhole pressure data. At present, the well is still operated as an intermittent producer with prolonged downtime periods allowing stronger pressure buildups at the perforations. It is planned to further increase injection rate to enhance pressure support in the region. An interwell water tracer campaign, currently in design for the field, is aimed to determine water breakthrough times and sources and establish reservoir flow patterns within the reservoir.
|File Size||1 MB||Number of Pages||13|
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