Heavy oil waterfloods have been operated in Saskatchewan and Alberta for up to 50 years, yet remarkably little discussion of the theory or operation of heavy oil waterflooding has been published. Conventional waterflood theory is based on assumptions that are not encountered in heavy oil reservoirs, and those theoretical and operational experiences should not be substituted. This editorial draws upon information from the relatively small number of significant theoretical and field discussions of Western Canadian heavy oil waterflooding available in the public domain to establish that the "state of the art," including proposed production mechanisms, prediction of performance, and improvement of performance, is extremely limited. Introduction An immediate challenge is deciding which waterflooded pools to include under the "heavy oil" umbrella, as imprecise definitions of heavy oil are used by both government agencies and waterflood operators. Definitions have at times been based on API gravity (a value of = 20 ° API is sometimes used), but often the driving criterion is geography. If a waterflood is located in an area near heavy oil cold production, it is sometimes simply classified as heavy oil, and given to a heavy oil group to operate. Emphasis on an oil-gravity-based definition of heavy oil is convenient, but unfortunate, as it de-emphasizes oil viscosity even though viscosity has repeatedly been shown to be a controlling parameter. Aversion to a viscosity-based definition for heavy oil may be due to occasional problems obtaining consistent heavy oil viscosity measurements(1, 2), and confusion about whether available viscosity values were collected using dead oil, live oil, or something in between. In stark contrast to this general neglect of viscosity data in heavy oil waterflood papers and articles, the most common informal statement about heavy oil waterfloods is, "you can't have a successful heavy oil waterflood if the dead oil viscosity is greater than" a particular value. Values in the 1,000 to 2,000 cp dead oil viscosity range (at reservoir temperature) are often cited as "the limit," but no study establishing a limit appears to exist. Searching the literature for information can be misleading. "Heavy oil" is often used in the title of waterflood articles because conventional oil waterflood technical staff consider oil with viscosity in the range of 3 to 10 cp (much lower than the hundreds to thousands of cp oil more typically waterflooded in Western Canada) to be heavy oil. The technology of Canadian heavy oil waterflooding likely started as conventional oil waterflood theory. It has evolved in a generally empirical manner, and in some ways is still more "art" than "science". The mobility ratio is so adverse that the "flood" process is likely over very quickly. The subsequent process is circulating water which brings enough oil with it for the process to be economic. This much longer "post-flood" period of Western Canadian heavy oil waterfloods is optimized using empirical methods that are often done differently by each oil company, engineer, pumper, etc. The result is a very limited written state of the art.

Heavy oil viscosity is one of the few criteria available to help predict if cold production will give economic rates, or if thermal processes will be required to reduce the oil viscosity to achieve the required rates. If cold production is selected, viscosity is again used to help determine whether vertical or horizontal wells should be used. Viscosity data are also used to adjust cold production exploitation strategies if the production rates are significantly lower than expected. Petrovera conducted an extensive viscosity data collection project in a newly developed Elk Point area reservoir with lower than expected, and more erratic than expected, cold production rates. Oil samples collected over short periods of time resulted in viscosity values for the same well varying by a factor of four or more, with similar variations between close-spaced wells. Collection of repeated samples and submission of those samples to several commercial labs resulted in similar viscosity measurement scatter. To further evaluate viscosity data scatter, multiple samples were collected from one well at the same time using the same procedures. These samples were then submitted to several labs in triplicate using three different well names to achieve an unbiased test. Reported viscosity scatter was again large. The objectives of this article are to:display the results of the study to bring this issue to the forefront for discussion; and,encourage commercial labs to develop an industry-wide standard method of heavy oil sample cleaning and viscosity measurement. Introduction Why Is It Important to Know Heavy Oil Viscosity Accurately? Heavy oil exploitation is an important segment of the oil and gas industry in Canada(1) and a number of other countries(2). Motivating factors for exploitation of Canadian heavy oil and bitumen are the large volumes of resources in place and the high historic demand for asphalt-based products that are more readily obtained from heavy oil and bitumen. Western Canadian heavy oil and bitumen reservoirs (Figure 1) have been exploited with varying degrees of success for more than 60 years(3). Early workers in the field of heavy oil and bitumen exploitation quickly determined that primary production responses (also called cold production responses) varied greatly from field to field. They also discovered that the addition of heat in the form of steam often greatly increased the production response. Viscosity became one of the most valued criteria in their efforts to predict production response from a new field using easily measured parameters. The popularity of the viscosity screening criterion has been demonstrated by the fact that virtually all technical papers on heavy oil production response or production process development include a discussion of oil viscosity. What is missing from the literature is an industry-wide standard of viscosity ranges and the corresponding recommended exploitation processes. This is because each company has its own 'best exploitation process vs.

A field test was run during 1997 and 1998 to collect preliminary data on a solvent gas injection process. The site selected for the test was a "typical" Frog Lake, Alberta, Cummings formation reservoir that had been depleted using PC pump-based cold production methods on both 4 hectare (10 acre) and 8.1 hectare (20 acre) spacing. At the time of solvent injection, area average recovery from the test location was 9.5%, and the existence of wormholes in the reservoir was strongly suggested by regional well-to-well water migration and production of reservoir sand at high initial rates and cumulative volumes. A solvent containing 33 volume % propane and 67 volume % methane was injected at two converted central producers until cumulative volumes of 2 million m3 and 4 million m3 were achieved. This paper discusses field observations during the injection, soak, and production periods. A number of circumstances contributed to a poor economic result, but the operational and technical information obtained should prove helpful to operators considering application of solvent injection processes. Introduction Cold Production in Western Canadian Regional Heavy Oil Sands PC pump-based cold production has expanded rapidly following initial development in the 1980s. This exploitation methodology provides a large percentage of the produced oil volume for most Western Canadian heavy oil producers. Some producers use only this method. Despite continued efforts to improve PC pump-based cold production technology, current methods generally leave 80 to 95% of the OOIP behind at economic limit. While this is a large oil-inplace target for follow-up EOR processes, the cold production process appears to have strongly altered reservoir conditions. Wormhole channels have been implied and described on the basis of observed high produced sand volumes and rapid migration of edge water and injected fluids and tracers(1–3). The reservoirs are generally pressure depleted. Solution gas, which appears to help power production through mechanisms described as either foamy oil flow(4–6) or more recently as extremely low gas mobility(7), often appears to "blow down" at the end of a well's life. Water influx, likely through wormhole networks, sometimes occurs at wells distant from the original oil/water contact. Thermal Production in Western Canadian Regional Heavy Oil Sands During the 1960s, operators attempted steam processes in selected heavy oil regional sands to recover a higher fraction of OOIP. It was soon determined that the typical H-40 casings with non-thermal cement would not withstand the resulting thermal stresses. Insulated tubing strings with or without packers were tried, but these strings were expensive, fragile, and often did not achieve theoretical performance in the field. Thermal completions in newer wells avoided wellbore failure due to the use of premium tubulars and collars, but other problems occurred. Often the steam had to be injected at pressures exceeding the formation parting (fracture) pressure to achieve acceptable heat transfer rates to the reservoir. This resulted in rapid steam channeling to neighboring wells, or to neighboring formations.

Cyclic steam performance at Husky's Lloydminster area Pikes Peak steam pilot has been very good but efforts to further improve performance have continued. This study was initiated to determine the causes of observed injection pressure variations from well to well, and during the stimulation of a given well. A further goal was to develop applications for this information. Analysis of the injection pressure data from the pre-1985 wells was limited in scope due to wide variations in injection rate and slug size; although low injection pressures were correlated to the presence of gas caps or bottom water; and a stepwise pressure drop through the first three cycles was documented. The relatively constant first cycle injection rates and slug sizes used for the 1985 wells allowed a more thorough analysis. Four injection pressure histories were observed; sustained high pressure and three types of pressure reduction. These pressure reductions were subsequently correlated to the proximity of: bottom water, gas caps mature wells and other recently stimulated first-cycle wells. Therefore, injection pressure data can be used to supplement the reservoir description data obtained from logs and cores. First-cycle data from the 1985 wells indicate that both overlapping the heated zones of previously stimulated neighbouring wells and pressure support from the aquifer could strongly affect first-cycle well performance. Net pay appeared to have less influence. During the second cycles at the 1985 wells interwell communication occurred at all wells except those which were particularly isolated, decreasing the validity of SOR-based individual well performance evaluations. The injection pressures increased with time at the isolated wells, establishing a fifth injection pressure history. The injection pressure history types of fourteen 1987 wells have been determined, and first cycle performance predictions were made using the 1985 well data. Introduction Husky's Pikes Peak steam pilot has given very good over-all performance(1, 2), but efforts to optimize pilot performance have continued. Early in the pilot's history it was assumed that steam injection pressures during a given cycle were fairly constant from well to well, and throughout the cycle at each well. Upon closer inspection significant steam injection pressure variations were observed for both initial cycle pressure and cycle pressure history, and a study was initiated to determine the causes, A similar study conducted to develop a method for detecting casing failures at Cold Lake wells was recently published, but no other in-depth discussions of this topic were found in the literature. Due to poorer economics associated with current lower oil prices, this study emphasized analysis of routinely collected injection well casing pressure data rather than acquisition of more costly data by installing downhole pressure gauges, drilling observation wells, running tracer tests, or obtaining 3-D seismic data. Before 1985, a variety of operating conditions were used to prove the economic viability of the pilot site, and to optimize operational procedures. Hence, the conclusions drawn from the nalysis of the injection pressure data for this period have been confined to general observations about the lower pressures observed at wells with gas caps or bottom water, or at post first cycle wells.

This concept paper explores the potential applications of air injection (in situ combustion) as a follow-up to cold production of heavy oils. Cold-produced fields are ideal potential candidates for air injection due to the significant resource that remains at the economic limit of cold production, and because wormhole- type channels are present in the depleted reservoir. The authors propose steaming the depleted reservoir for a short period of time to collapse the wormholes, thus creating high permeability heated channels. Reservoir ignition and air injection would follow, with the heated channels providing a flow path for the mobilized oil to reach the production wells. The steam/combustion combination would be highly effective in thin reservoirs, where extended steam injection is uneconomic. Additionally, this process addresses the three technical causes for failure in heavy combustion projects: ineffective ignition, inadequate air injection rates, and temporary plugging of the formation due to blockages caused by high liquid saturations. An overview of cold heavy oil production and heavy oil by in situ combustion is provided, as well as a detailed discussion of the proposed process. Introduction Cold Production in Western Canadian Heavy Oil Regional Sands Western Canada contains extensive heavy oil and bitumen deposits, as is shown in Figure 1. Early primary production of this resource using reciprocating pumps in vertical, directional, or slant wells was only economic in the Lloydminster Block; thus, most of the existing geologic studies are for this area(1–3). Following the development of progressing cavity (PC) pumping technology in the 1980s, cold production from these wells (vertical, directional or slant) was expanded rapidly to several additional areas, including Frog Lake, Elk Point, Lindbergh, and portions of Cold Lake and the Primrose Block. This exploitation methodology provides a large percentage of the produced oil volume for most Western Canadian heavy oil producers; in fact, some producers use only this method. Most cold production of heavy oil has been conducted in regional sands from the Lower Cretaceous Mannville Group (see Figure 2). Stratigraphic nomenclature varies locally, but, in general, most Lloydminster area regional sand cold production is from the Sparky and Waseca sands, while most of the Frog Lake, Elk Point, and Lindbergh cold production is from the Cummings.Regardless of the nomenclature, from a reservoir engineering perspective, these sands are characterized as being relatively thin, clean, with high porosity and permeability, and containing high saturations of heavy oil(4). Figure 3 is a plot of the estimated distribution of oil in place vs. sand thickness for the Lloydminster area, and Table 1 describes regional sand properties. Bottom water and edge water are common features, and a significant fraction of the wells in this region become uneconomic due to rapid water influx. Despite continued efforts to improve PC pump-based cold production technology, current methods generally leave 80 to 95% of the OOIP behind at the economic limit. This is a large oil-in-place target for follow up EOR processes; however, the cold production process appears to have strongly altered reservoir conditions from their original state.