Reservoir characterization is important to EOR and numerical simulation studies, especially for complex naturally fractured reservoirs with low-permeability matrix rock. Solvent movement and volumetric sweep are controlled by fracture distribution and connectivity and by matrix permeability variation. All these factors were considered in our reservoir characterization and simulation study.The reservoir characterization was so effective that, in a 63-well simulation study, 70% of the wells were history matched on the first simulation runs without modification to the original geologic/petrophysical data. This can be attributed to the team approach of using geological, reservoir engineering, and petrophysical input.

Dramatic increases in oil production rates have been achieved in many Canadian heavy oil reservoirs. These reservoirs are 30% porosity unconsolidated sandstones with oil ranging from 500 to 12,000 cP viscosity. Furthermore, many of these reservoirs have proven to be almost impossible to exploit economically with horizontal wells or with thermal processes. After reviewing the mechanics of CHOP (Cold Heavy Oil Production), the production history of the Luseland Field in Saskatchewan is reviewed. This is almost a unique case history because conventional production, horizontal wells, and CHOP have all been attempted in a small geographic area. Encouraging sanding resulted in over a four-fold increase in oil production rate and a total extraction ratio now just in excess of 11% overall. An aggressive CHOP program implemented after many years of conventional production and after a six-well horizontal production program achieved this increase. Conventional production was marginally economic, but the horizontal wells were failures. Several other case histories are summarized to demonstrate that CHOP wells in these reservoirs are usually just as productive as much more costly horizontal wells. We believe that CHOP technology is a far better option than thermal stimulation or horizontal wells in many cases where the reservoir state and rock properties are suitable. CHOP (Cold Heavy Oil Production) CHOP technology began in the late 1980's in Canada and has evolved and matured in the 1990's to the point where it is acknowledged to be the first production option to be evaluated for heavy oil exploitation in unconsolidated reservoirs. The mechanics of heavy oil production have been the subject of many articles addressing models, mechanisms and practical implementation. The mechanisms for oil rate enhancement through sand production in these reservoirs are associated with four factors:1,2,3,4,5,6,7 1. When the sand matrix is unconstrained (no screens or other impediments) and is allowed to move with the viscous fluids into the well bore, the basic Darcy flow velocity (vf - vs) is increased, and the oil mobility is thereby enhanced.8 2. Continued sand production from a CHOP well leads to the growth of a disturbed zone of higher porosity and permeability9, likely as the combined result of formation dilation (+?V ? +f ? +k) and the generation of piping channels (long, small drains). This affected zone can approach a size of 100–200 m diameter after 1000–2000 m3 sand production, and has been repeatedly detected using surface 3-D seismic mapping methods. 3. Canadian heavy oils all contain gas in solution (h ~ 0.2 bar-1)1. On production (-?p), a non-equilibrium foamy oil phasex is generated that helps destabilize the sand and accelerates flow to the wellbore through internal expansion of the flowing slurry. In most CHOP wells, no continuous gas phase develops in the formation, even after many years. This "foamy oil" phenomenon has been the subject of much speculation and testing over the last few years,11,12,13 and much remains to be learned. 4. Continued sand movement prevents the formation of pore blockages through fines trapping, asphaltene precipitation, and other near-wellbore mechanical skin effects.14,15 i h is Henry's constant, in units of volume of dissolved gas per volume of liquid per atmosphere pressure. It is a more rigorous and consistent method of expressing solution gas content, as it is independent of depth and pressure.

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Actual production data of Winter Field were examined for production rates, oil cut, cumulative oil produced and reserves per well in relation to well length. The log oil cut vs. cumulative oil production per well of groups of wells plots showed that the reserves at a 2% oil cut was the same despite the different lengths of these wells. Published data were next examined to establish the relationship between well length and reserves. It is obvious that the relation between reserves as a function of well length is not a linear relationship for the entire well length examined. This relation shows that as the well length increases from 200 m to roughly 500 m there is a linear increase in reserves. The slope of the line is less than one (0.7); as the length increases beyond 600 m there is very little increase in the reserves. This could explain why the Winter wells all have the same reserves. These groups of wells varied in length from 574 m to 1,110 m; that is, they are all in the length range (greater than 500 m) that gives the maximum reserves(1). In order to verify this conclusion and utilize it to increase the reserve from existing and future wells a series of well workovers and treatment programs were carried out. Newly drilled wells were completed in such a way as to use the conclusions and recommendations of these programs. Introduction The Winter field (Figure 1) has been developed utilizing horizontal wells to produce heavy oil (13.7 API oil of 2,800 – 3,800 cp. viscosity) in a 12 m thick Cumming Sand underlain by a very strong aquifer. The oil cut vs. oil cum. per well plots for each phase (wells drilled in a specific year) are shown in Figure 2. It is obvious that the reserves per well at an economic oil cut of 2% are essentially the same for the different phases. It is interesting to notice that the average well length for the different phases ranges from 574 m to 1,111 m. Data for over 250 horizontal wells producing oil over water reservoir in Saskatchewan published in SEM publication were analysed and the reserves as a function of length are shown in Figure 3. This figure illustrates the non-linear nature of the relationship between reserves and well length. For example a well of 200 – 300 m length has a reserves of 9,000 m3 while a well of 1,000 – 1,100 m has a reserves of 15,000 m3; rather than the 30,000 – 40,000 m3 expected in a linear correlation. Detailed analysis of every well in the Winter Field was carried to identify potential reasons for better or worse performance. A series of water shut-off treatments and workovers were carried out. External casing packers were utilized for formation isolation and proved to be effective. Finally, the information gained from all of the above is being tested in some of the 1995 drilling program through a new completion practice targeting reserves maximization with minimum effect of initial rate.