Scale Dissolver and Scale Squeeze Operations in an HPHT Field in the North Sea
- Alexander Nelson (Schlumberger) | Trine Algrøy (Schlumberger) | Kjetil Netland (Schlumberger) | Øystein Sæther (Equinor ASA) | Rita Iren Johnsen (Equinor ASA)
- Document ID
- Society of Petroleum Engineers
- SPE International Oilfield Scale Conference and Exhibition, 24-25 June, Virtual
- Publication Date
- Document Type
- Conference Paper
- 2020. Society of Petroleum Engineers
- 5.2 Reservoir Fluid Dynamics, 4.1.2 Separation and Treating, 3 Production and Well Operations, 4.3.4 Scale, 7 Management and Information, 7.2 Risk Management and Decision-Making, 4.1 Processing Systems and Design, 4 Facilities Design, Construction and Operation, 7.2.1 Risk, Uncertainty and Risk Assessment, 1.6 Drilling Operations, 5.5.2 Core Analysis, 1.8 Formation Damage, 5.2 Reservoir Fluid Dynamics, 3 Production and Well Operations
- HPHT Field, Chemical Qualification, Scale Squeeze, Scale Inhibitor, Scale Dissolver
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This paper presents a case history of scale treatments performed in a well producing in the North Sea. Kvitebjørn is a gas and condensate producer with high reservoir pressure (480bar) and high temperature (152°C). Well A-7 T2 started production in January 2014 and has a history of a carbonate scale precipitation.A few months after start-up, formation water breakthrough was observed in addition to a reduction in Production Index.
Due to challenges with removing scale by wireline, interventions using scale dissolver were performed in late 2017 and early 2018. The second dissolver treatment was followed by a scale squeeze to protect the well from further scaling. The chemicals used were qualified according to the Operator’s technical specifications. Due to high reservoir temperature, thermal stability was vital in the qualification process. The formation permeability was moderate, which was important to consider when evaluating the risk of formation damage.
The environmental category for the chemicals versus their performance was an important factor in the qualification process. Modelling programs were used to assess placement distribution under various bullhead pumping conditions. For the scale squeeze, a modelling program was used to simulate treatment lifetime using isotherms derived from laboratory core flood testing.
Water samples were taken from the well and analysed onshore in the supplier’s laboratory. Following the scale squeeze, water samples were taken from the well during the entire treatment lifetime. Ion concentrations and residual inhibitor concentrations were monitored together with production parameters to assess the scale situation in the well.
Following the treatments, the well showed an increased gas production. The well produced 1.2MSm3 at 40% choke before the treatments and 1.2MSm3 at 6-7% choke after. Laboratory work combined with field experience from this first well that was treated, forms the basis for possible future treatments. Being able to treat wells through pro-active and efficient scale inhibitor squeeze treatments will allow for continued production of wells exposed to scale risk, avoiding the cost and risks associated with mechanical scale removal and avoiding production deferral associated with potential dissolver jobs.
|File Size||2 MB||Number of Pages||21|
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