Polymer flooding is becoming increasingly more common and more successful in western Canada. In the year 2011, western Canada produced over 1,600,000 m 3 of oil using polymer flooding. In the statistical study reported here, production, injection, reservoir, and operating data were gathered from 32 polymer floods of heavy and medium oil in western Canada. Success was highly variable. Incremental recovery ranged from 0.5 to 14% of the original oil in place over periods lasting between 1 and 9 years. Half of the polymer floods in the project showed a decline in water cut. Oils of very high viscosity and low gravity-as high as 5,000 mPa·s for dead oil and as low as 15°API gravity -were successfully flooded using a polymer solution.Operational factors that were most significant to flooding success were injection volumes and rates; inclusion of horizontal wells, in particular injection wells; and water quality. Water quality was a major issue, suggesting that the success of many projects comes down to handling operational issues rather than project concept or design. Polymer integrity and injectivity led to many of the operational difficulties.
This study presents a successful application of multivariate partial least-squares (PLS), response surface methodology (RSM), and artificial neural network (ANN) to develop a new diagnostic tool for performance prediction of waterflooding in heavy oil reservoirs. The data used in this study consist of 120 operational and reservoir parameters for 177 waterfloods in heavy and medium oil reservoirs in western Canada (i.e., Alberta and Saskatchewan). This study also used 15 numerically devised indices for performance evaluation of water injection, based on collected injection and production histories of studied waterfloods. To reduce the number and complexity of input parameters of ANN models, a comprehensive PLS analysis was conducted. In addition to parameter selection, the PLS model provided a more in-depth understanding of differences between heavy and medium oil waterfloods. Next, RSM was used to improve the quality of the database for a selected combination of 38 reservoir and operational parameters by predicting some of the missing data. Finally, ANN models were developed using the feed-forward backpropagation algorithm with momentum for error minimization. The developed models show the superior ability of the ANN for creation of an efficient reservoir engineering tool for fast performance prediction of waterfloods using easily obtainable operational and reservoir parameters. The developed models in this study can be incorporated into reservoir engineering, risk assessment, and production optimization software programs to improve the quality of predictions based on more than 50 years of waterflooding experience in western Canada.
A coalescer column —a simple, inexpensive and environmentally friendly technology —successfully removed water from produced heavy oil emulsions. The laboratory study tested the use of the column and the effects of column length, column packing size, temperature, flow rate, demulsifier concentration and water addition. The use of the column improved basic sediment and water (BS&W) values after 4 hours of settling time by an average of 38%. Flowing the emulsions through the column at lower temperatures and much lower demulsifier concentrations matched the results of conventional treating. The results indicated that incorporating a coalescer column into a treatment facility allowed the reduction of demulsifier concentration from 250 ppm to 70 ppm, translating to an annual cost savings of $320,000 to $1,100,000 per battery. The column also promoted faster treating. Water droplets grew by as much as 34%, suggesting that treating time could be sped up by an average of 21% and as high as 80%. Introduction Heavy oil producers have reported that chemical costs represent the highest fraction of their operating expenses. A small survey of battery operators showed that demulsifier concentrations at heavy oil batteries ranged from 200 to 333 ppm (1 L/5 m3 to 1 L/3 m3) in 2001(1). These operators also reported that demulsifier doses were rising; within the last five years, the concentration of demulsifier used to treat a typical heavy oil has risen by 25 to 50% for many reasons. A battery in the heavy oil region can easily spend over $100,000 annually on demulsifying chemicals. The two treating batteries which supplied emulsion samples for this set of experiments were estimated to spend between $400,000 and $1,100,000 every year on such costs. Heating costs are also considerable. Some heavy oil batteries heat their pressurized treating vessels to 130 °C. In addition to the cost of heating, producers are becoming increasingly aware of the importance of reducing greenhouse gas production. An alternate, inexpensive and environmentally friendly technology to help separate oil and water would be highly desirable. One promising separation method is of the passive mechanical type: a coalescer column. Over the past 18 years, the Saskatchewan Research Council (SRC) and the University of Regina have applied this technique to break water-in-oil emulsions(2–8). Whereas our previous work focused on resolving slop oils, this study applied the coalescer column to the treatment of wellhead emulsions. A literature survey on the subject of coalescers and resolving crude oil emulsions is deceptive. A number of researchers use the word coalescer, but apply it to plate separators or pipes with no packing. Our use of the term restricts it to a pipe filled with some sort of porous packing material which aids in the coalescence of dispersed droplets of an emulsion. In their review of the literature on coalescing media, Stocker et al. listed the many types of packing materials that have been tested(9). These fall into the categories of fixed media, granular packing and fiber packing. The materials range from high-tech oleophilic plastic fibers to such exotic packing materials as granulated black walnut shells.
A statistical study of 166 western Canadian waterfloods recovering heavy and medium gravity oils revealed new findings about best operating practices for heavy oil waterflooding. In classical light oil waterflooding, operators are advised to start waterflooding early and maintain the voidage replacement ratio (VRR) at 1. The study, however, produced surprising results for 2 parameters − among the 120 reservoir and operating parameters investigated − that ran counter to the recommended practices of classical light waterflooding. Delaying the start of waterflooding until a certain fraction of the original oil in place was recovered was found to be beneficial. Secondly, varying the VRR was shown to correlate with increased ultimate recovery ─ periods of underinjection are needed, although a cumulative VRR of 1 should be maintained.Ultimate recovery was correlated with the primary recovery factor at the start of the waterflood. No trends appeared when the full set of 166 waterfloods was inspected. However, when the dataset is analyzed by ranges of API, a "sweet spot" of improved ultimate recovery was observed in a very narrow window of oil recovery factor prior to the start of waterflooding. Graphs of each category showed this "sweet spot" window where improved recovery occurred. These categories were API ranges; as well as ranges of permeability*height/viscosity (kh/μ); and pattern development.Also increases in ultimate recovery were observable when we examined graphs of ultimate recovery versus the fraction of injection volume that was underinjected ─ but again, only when the data was analyzed by the ranges. A certain period of injection when the VRR was less than 0.95 resulted in increased ultimate recoveries. However, it is important that this period of VRR < 0.95 be offset with periods of increased VRR so that the cumulative VRR cycles around 1.0. Again, each range manifested a narrow "sweet spot" for where this increase in ultimate recovery occurred.
Microwave treatment has successfully treated slop oils and sludges of light and medium crude. This paper reports its extension to slops derived from heavy crude oil.Scientific and industrial treatments using microwaves are usually limited to frequencies of 2450 MHz and 915 MHz. However, this study used a variable frequency microwave to examine the effect of applying radiation between 5800 and 7000 MHz. Microwave treatment of an unusually stable, high-solids slop oil from the Elk Point region did not break the slop oil, but it did improve oil-solids detachment by up to 29%. The frequency centered on 6400 MHz was the most effective. Although preliminary, these results certainly warrant a closer look at variable frequency microwave treatment of slop oils, particularly for more typical slop oils of lower stability, as a way to significantly reduce oily waste volumes and disposal costs.
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