This simple formulation assumes no changes in

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This simple formulation assumes no changes in volumetric heat capacity or project volume with time. Where there are sufficient TO wells, the direct method offers the advantage of simplicity and fewer assumptions when determining the required injection during routine monitoring after establishing a steamchest. However, the direct methods do not take into account heat losses that occur beyond the area being analyzed (e.g. , production wellbore, surface lines, influx and efflux). Application of Heat Management Figure 10 shows the heat injection history of a project along with a comparison of the heat calculated by several analytical methods and the TO well direct method. One can see that there is general agreement between the two analytical methods which include heat losses from production, and the data from the direct TO well method. The Vogel method without consideration of production losses under-predicted heat requirements. It is also evident that there was a period in 1994 during which this project was over-injected. This was followed by a period of slight under-injection, and then balanced injection. Figure 11 demonstrates how decreasing the injection rate does not necessarily translate to a loss in oil production rate. This project was being greatly over-injected in 1992-1993. Heat injection was reduced by approximately 60% in two steps, yet we see that oil production was not adversely affected. Similarly, Figure 12 shows another project in which reduction from 15,000 BSPD to 4,000 BSPD in two steps over a period of two years resulted in no change in the well- established production decline behavior of the reservoir. Finally, Figure 13 shows a case where a project which had adequate injection and well density showed no response to increased steam injection and increased well count. If a project is receiving sufficient heat and has sufficient well density, the rate is fixed by the rate of gravity drainage – increased heat and well density will not accelerate oil recovery. Heat management is an interactive reservoir management process. It should involve production monitoring, temperature surveillance, an integrated reservoir model, and surface steam measurement/control. Although this paper has concentrated on the subsurface aspects, measurement and control of steam distribution (including liquid/vapor phase splitting) in surface facilities and the wellbore is also very important. Conclusions Thermal recovery in California is at mature stage in its life cycle. Widespread adoption of demonstrated technical principles (e.g. , heat management) may not occur until forced by commercial circumstances. Increased efficiency has come from both and improved understanding of the steamflood process and consolidation of the industry.
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