Solving Ultra-High Temperature Scale Challenges: A Case Study of Re-Use of Polymer Flooding Waters for Heat Exchangers
- Zhiwei David Yue (Halliburton) | Ping Chen (Halliburton) | Vlad Draghici (Halliburton) | Megan Westerman (Halliburton) | Martijn Huijgen (Halliburton) | Angelo Privitera (Halliburton) | John Hazlewood (Halliburton) | Thomas Hagen (Halliburton)
- 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
- 4.3.4 Scale, 5.3.6 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex), 7.2 Risk Management and Decision-Making, 4.1 Processing Systems and Design, 4 Facilities Design, Construction and Operation, 2.1.3 Completion Equipment, 4.1.2 Separation and Treating, 7 Management and Information, 5.4 Improved and Enhanced Recovery, 5.4 Improved and Enhanced Recovery, 7.2.1 Risk, Uncertainty and Risk Assessment
- ultra-high temperature, heat exchangers, polymer flooding waters, scale control,
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An oilfield operator relies extensively on heat exchangers (Hexs) to break heavy oil emulsions. A workhorse inhibitor worked reliably to control thermally induced scale precipitation caused by local hard waters. However, an upsurge of scale-related Hexs tubing blockage occurred during a harsh winter that coincided with a breakthrough of enhanced oil recovery (EOR) polymer into some water sources. Through comprehensive lab testing, root causes of the failure were identified. A new product was developed featuring superior tolerance to variable production parameters, especially Hexs temperatures.
Scale inhibitor efficacy is strongly influenced by overall scaling conditions including water chemistry, temperature, pressure, and presence of incompatible chemicals. In this study, scale precipitates collected from Hexs were characterized using environmental scanning electron microscopy techniques. New inhibitor chemistries were screened through thermal aging; then evaluated for inhibition performance by dynamic tube blocking methods at temperatures ranging from 42°C to 171°C. An additional performance test was designed for the final candidate to further investigate adverse impacts from the EOR polymer and incumbent scale product if a dual-product treatment is required throughout the field fluid system.
The incumbent effectively inhibited scale formation at ≤120°C but showed reduced performance at 160°C. This result is consistent with field records indicating most tubing blockages occurred during the coldest days when Hexs temperature was raised to 160°C to increase heat to treat fluids. Meanwhile, it also suffered antagonistic effects from the EOR polymer. A dozen new inhibitor chemistries were studied including polymers and phosphonates. Polymeric inhibitors had higher thermal aging ratings but were less compatible with the waters involved. Ideal candidates must have thermal stability, high-temperature inhibition performance, and applicability to wide ranges of operational conditions, including Hexs temperature, water hardness, bicarbonate, and foreign substances. Thus, a single product can be applied to the entire field and simple dosage adjustments can readily handle most expected scaling risks. The new product passed all the criteria and significantly reduced operating and equipment replacement cost since deployment.
This paper provides a unique scaling challenge that combined ultra-high temperature and EOR polymer influence, and a systematic approach to understanding and resolving the issue.
|File Size||1 MB||Number of Pages||15|
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