The Pembina Cardium reservoir is the largest conventional oil reservoir in Canada, containing 1.1 × 10 9 m3 of original oil-in-place. The main recovery operation is water flooding. Field observations and reservoir analyses confirm that in situ wax precipitation and particulate deposition impair both injectivity and productivity in this pool. Work to resolve the contributions of several damage mechanisms involved laboratory experimentation and reservoir engineering analysis. Phase equilibrium studies determined the conditions necessary for wax deposition in the reservoir. Coreflood studies characterised the wax deposition behaviour and the resulting permeability reduction. Reservoir engineering analysis included the development and application of analytical and numerical simulation models to describe wax/particle transport and deposition in the reservoir to explain observed field performance. This investigation has resulted in new analytic methods not previously reported in the technical literature:laboratory and reservoir analysis techniques to identify formation damage mechanisms affecting productivity and injectivity and to measure relevant parameters to quantify damage;phase envelope for wax deposition using reservoir fluids;injectivity analysis of field injection wells and quantification of the reduction of injectivity resulting from fill-up, fluid displacement and formation damage;description and performance of analytical formation damage models in fitting observed field injectivity data;incorporation of key formation damage mechanisms in reservoir simulation models to enable history matching of field performance. Introduction In late 1993, the major operators in the Pembina Cardium field, with support from their affiliates, began a collaborative effort to determine how to improve performance and recovery for the pool. This paper focuses on part of the efforts to understand the principal causes of formation damage in pool. The Pembina Cardium Field in west-central Alberta was discovered in 1953 and waterflooding has been the principal recovery method since 1960. in most production wells, a steady decline is seen in both oil and total fluid rates. Injection wells require increased pressure to maintain injection volume targets, or else experience reduced injection volumes. Formation damage is a probable cause for these behaviours. Older studies by various operators concluded that while clay swelling and fines migration do occur in parts of the field, these cannot explain field performance. Indeed, numerical simulations have used declining well indices to achieve history matches, but no specific physical justification was identified. Anecdotal field data shows the major operational problems in the field are paraffin deposition, fines migration, corrosion, scale, and bacteria. The purpose of this study was to investigate the principal causes, locations, and magnitudes of formation damage. Field Observations Wax Deposition. Wax deposition in production well tubulars is the most significant operational problem encountered in the Pembina Cardium Field. This problem is endemic to production wells and it is becoming harder to clean up. Historically wax has been removed by hot oiling the wells; however, operators have switched to other wax removal methods, including strong solvents, chemicals, and microbes. The use of scrapered rods in the wells is now common practice. P. 277

The Suffield Caen reservoir contains 17API heavy oil and the pool has been under waterflooding since 1996 with water cut of 96%. Primary and secondary oil recovery is 15 -20% of OOIP. A major problem encountered in waterflood was poor sweep efficiency and high water cut caused by high water/oil mobility ratio, as water quickly broke through the reservoir owing to fingering effects. It is known that sweep efficiency during waterflood can be improved significantly by increasing the viscosity of injected water by use of polymer solution, thus generating a more favorable mobility ratio and enhancing oil recovery. The results of reservoir simulation studies suggested that polymer flood would achieve incremental recovery factor of 7 -12%, and coreflood results indicated that 29 -32% of incremental recovery is achievable by 0.5 pore volume (PV) of polymer injection.Core floods including polymer, surfactant/polymer(S/P) and alkali/surfactant/polymer (A/S/P) were conducted through lab experiments and eventually polymer flood was selected as a pilot project to improve oil recovery for the Caen reservoir on the basis of polymer, S/P and A/S/P core flood results and project economic evaluation.Polymer injection started in the reservoir 15 months ago and a very positive response has been seen as oil cut has increased to 10% from 5% and oil production rose to 600 bbl/d from 400 bbl/d. Therefore, the polymer flood pilot project is continually implemented and the polymer flood is planned to extend to similar reservoirs in the Suffield area.There is a large amount of conventional heavy oil resaves in the West Canada Basin, so far the primary recovery factor is only 10%, there is a big potential to enhance oil recovery by polymer flood. This polymer flood pilot project provides valuable experiences and guidance to field application.

Between 1990 and 1994, 18 horizontal wells were drilled and completed in the Pembina Cardium pool. Increased application of this technology in the pool has been curtailed by limited understanding of the performance of these wells and lack of reliable prediction models. This paper focuses on the analysis of performance of the 18 wells and the development of a methodology leading to a reliable performance prediction model for horizontal wells in the pool. The model was developed using analytical modelling techniques. A major advantage of the analytical technique over reservoir simulation, besides its low cost and quick turn-around, is that it involved more focus on key performance drivers. The analytical model couples a material balance model with a reliable horizontal well productivity model.This methodology provides deep insights, particularly into the performance of horizontal wells within a stratified reservoir under waterflood. It shows that traditional methods of modelling horizontal wells by history matching vertical wells or using type curves to establish reservoir parameters may lead to inaccurate or unreliable performance predictions, particularly in layered reservoirs under waterflood. A material balance model coupled to a proper horizontal well productivity model, the application of a detailed reservoir description, and correct averaging techniques are critical to successful performance forecasting.The methodology developed in this study has resulted in the identification of key reservoir characteristics leading to selection of reservoir targets for successful application of horizontal wells in the Pembina Cardium pool.