Discussion/Reply: Downhole Steam Generation Pushes Recovery Beyond Conventional Limits
- Jeff Jones (E&B Natural Resources) | Laura Capper (CAP Resources) | Myron Kuhlman (MK Tech Solutions) | George Vassilellis (Gaffney Cline Associates) | M.J. Schneider (Global Marine Drilling Company) | Nick Fitzpatrick (World Energy Systems)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- September 2012
- Document Type
- Journal Paper
- 132 - 136
- 2012. Copyright is retained by the author. This document is distributed by SPE with the permission of the author. Contact the author for permission to use material from this document.
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The authors of paper SPE 150515, titled “Downhole Steam Generation Pushes Recovery Beyond Conventional Limits,” (JPT June 2012), are commended for bringing the topic to the forefront. However, the article is a little too optimistic and may lead the reader to wrong conclusions. With all the perceived promise over the decades, this technology is still in the conceptual stage, especially in the reservoir EOR mechanisms envisioned by the authors and in the basic operational design.
Playing devil’s advocate, here is a short list of possible “cons” to accompany the article’s list of “pros” for the process:
- Conventional steam-enhanced oil recovery (EOR) depends on the latent fraction of heat contained in quality steam. Sensible heat in water has proven to be of little help in the recovery of incremental oil. For the typical project that operates at <<100 psig, the latent fraction of heat in the steam is in the range of 80%. For steam at the proposed >2,000 psig the latent fraction falls to about 35%. If applicable, this changes the mechanism displacing oil from the reservoir; it is no longer a conventional steamflood.
- In general, the deeper the reservoir, the hotter the formation. The hotter the formation, the lower the oil viscosity and less need for steam. In California, the typical reservoir at 2,000 ft is 130°F and at 5,500 ft, it is 200°F. Granted, other parts of the world have lower temperatures at depth (e.g., the Alberta fields are about 130°F at 5,000 ft); however, this is a limiting factor for deep thermal processes.
- Deeper reservoirs tend to be tighter sands and the downhole steam generation (DHSG) demands that all the fluid sent downhole is injected. This will require either reduction of injection, which has implications for the reservoir process, or injecting at fracture pressures, which has its own set of problems.
- There are few better filters in the oil field than a wellbore sand face. Couple this with the inevitable particulate generation in DHSG, and well plugging problems are likely to occur.
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