Steam or CO 2 injection methods account for most of the oil recovered worldwide with Enhanced Oil Recovery (EOR) methods. Currently heavy oil production is less than 7% of the world's oil production; this percentage is not expected to increase dramatically without significant changes in reservoir management. Steam and CO 2 have been used successfully since early 1960s --steam in viscous heavy oils and CO 2 mostly in pressurized light oil fields but also in some heavy oil fields. What limits a wider application is depth and high pressure for steam and CO 2 availability for the relatively large inventory of light oil fields that exist worldwide. Although there is some overlap in fields that could benefit from either application, there are not many recorded attempts to implement both methods simultaneously. Air injection, although it was tried first as an EOR method, has not been widely implemented as in-situ combustion is difficult to control in shallow reservoirs and especially without water coinjection.The paper describes the benefits that result from operation of a downhole steam generation (DHSG) which combines thermal and nitrogen or CO 2 EOR. In addition, by controlling the ratios of steam, excess CO 2 and excess O 2 (where applicable) it is possible to use in-situ oxidation in a controlled manner and accelerate production of oil. Moreover, the CO 2 that is generated by in situ can be used elsewhere. The paper includes discussion of conceptual reservoir simulation and economic studies that demonstrate the applicability of DHSG in deeper warm-climate conventional heavy oil fields, as well as challenging arctic environments.Advances from the aerospace industry that enabled this DHSG system, the surface processing design, and well placement strategies are also discussed in this article. They provide an overview of the entire recovery system and present an opportunity to develop both virgin resources and oil fields that were prolific in primary and secondary operations and are rightfully candidates for EOR.

Discussion/Reply 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.

Management of produced water from conventional plays and shale and tight oil and gas plays is driving subtle yet potentially consequential changes in certain regions and Underground Injection Control (UIC) formations. UIC operation topics of interest include induced seismicity (from UIC injection, extraction, or unknown/anomolous activity), formation pressurization from years of UIC injection, and reallocation of produced water from originating "tight" producing formations to more receptive conventional, depleted, or waterflooded formations, resulting in formation pressure changes. Early signs of diminished formation health or threats to operations continuity can include: Barely felt (low magnitude) induced and anomolous earthsquakes - which nonetheless are a cause of significant concern to the public – and by extension, landowners, stakeholders, and regulators.Reduced formation injectivity – suggesting that injection rates should be "dialed back", or that injection pump pressures be increased, or that water be transported further to more receptive injection formations. If encountered, stresses can contribute to cost overruns, impairment to operations schedules, additional oversite to assure regulatory compliance, reduced public goodwill, and potentially, impairment of industry’s social license to operate. Through analysis of publicly available UIC operations data and well completion data, we evaluate methods which might help to qualitatively assess UIC issues with macro, regional, local and subsurface formation perspectives. The methods discussed may provide operators with a consistent simple methodology to qualitatively identify those assets and UIC formations with higher potential relative risk which may warrant more detailed exploration and possible risk mitigation.