Impact of the Distribution of Calcite Concretions on the Performance of SAGD
- Ian Donald Gates (U. of Calgary) | Jing Yi Jacky Wang (University Of Calgary) | Bill Robinson (Paramount Resources) | Gary L. Bunio (Barrick Energy)
- Document ID
- Society of Petroleum Engineers
- SPE Heavy Oil Conference Canada, 12-14 June, Calgary, Alberta, Canada
- Publication Date
- Document Type
- Conference Paper
- 2012. Society of Petroleum Engineers
- 5.5 Reservoir Simulation, 5.3.9 Steam Assisted Gravity Drainage, 4.3.4 Scale, 4.6 Natural Gas, 4.1.5 Processing Equipment, 5.8.5 Oil Sand, Oil Shale, Bitumen, 1.14 Casing and Cementing, 5.1.5 Geologic Modeling, 5.1.1 Exploration, Development, Structural Geology, 2.4.3 Sand/Solids Control, 2.2.2 Perforating, 5.4.6 Thermal Methods, 1.6.9 Coring, Fishing, 4.1.2 Separation and Treating
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Carbonate-cemented concretions in Grand Rapids oil sand reservoirs are common with length scales up to several meters wide and high. The concretions can be found embedded in unconsolidated oil sands distributed irregularly within the formation. From a Steam-Assisted Gravity Drainage (SAGD) recovery process point of view, calcite concretions are non-productive rock which can interfere with the growth of steam chambers. However, depending on the length scales of the spatial distribution, sizes, and shapes of the concretions, thermal dispersion can occur which can potentially enhance heat transfer within the oil sands formation. Thus, although calcite concretions are heat sinks that reduce the oil in place, they could potentially aid in steam chamber conformance. Heterogeneity of the SAGD steam chamber depends on the heterogeneity of the underlying geology. Here, the impact of spatial distributions and size of concretions on the performance of SAGD is examined. The temperature distribution (chamber growth) and steam chamber height and shape are examined. The results reveal that steam chamber growth and conformance is impacted by the presence of calcite concretions. Concretion nearer the SAGD wellpair have the largest impact since they interfere with steam chamber growth from the earliest stages of the process and the impact grows throughout the process yielding cold spots along the wellpair. This provides a means to decide length scales for placement of wellpairs to optimize chamber conformance and SAGD performance.
The Grand Rapids Formation in the Hoole area of Northern Alberta, Canada consists of a relatively clean oil sands of thickness between about 15 and 27 m. The key feature of this oil sands reservoir is the presence of embedded calcite concretions. Calcite cement is a commonly found diagenetic feature often found in sandstone reservoirs and although it can cement beds leading to laterally extensive tabular barriers within the sand, it most often exists as discrete cemented concretions that sit within the sandstone. Calcite cementation in the form of concretions appears to be seeded at irregularly spaced locations within the sandstone formation. Calcite concretions are typically spherical (typically small) or oblate spheroids or irregular in shape with sizes ranging from tens of centimeters to several meters in extent. In some cases, multiple concretions have grown together leading to a cement body that appears as a prolate spheroid in shape. The spatial distribution, both vertical and horizontal, of concretions is typically random with no clear patterns thus it remains unclear how to assess their impact on flow and heat transfer in thermal recovery processes.
The in situ viscosity of bitumen from the Grand Rapids Formation in Alberta, Canada is several million cP. Given the depth of the formation, which is relatively shallow and the solution gas-to-oil ratio is relatively low, the preferred process for production of the Grand Rapids oil sands Formation is Steam-Assisted Gravity Drainage (SAGD), displayed in cross-section in Figure 1. Oil sample testing has revealed that the oil viscosity varies by a factor of about two - at the top of the Grand Rapids the viscosity of the bitumen is equal to about 2 million cP whereas it is equal to about 5 million cP at the bottom of the formation. At steam temperature (220°C at 2,300 kPa), the viscosity of the top and bottom oil drops to below 10 cP.
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