The last few years have seen the end of the Athabasca land play and the revival of interest in Alberta's bitumen resources in carbonate reservoirs. Of these, the Grosmont Formation is the most promising in terms of resource size and concentration. It is also the best known, in terms of having been the subject of several in situ pilots operated in the late '70s and early '80s. The data recorded from these early pilots is priceless in terms of having a touchstone of reality for new process concepts. On the other hand, the interpretations written in those days ('before gravity') are not necessarily as helpful. This paper looks at the Grosmont in terms of facts and fundamentals, and presents the case for Grosmont exploitation. There is good evidence that the Grosmont has very high bulk permeability as a result of karst porosity development and fracturing. This bodes well for the use of modern gravity drainage methods in the Grosmont. Introduction Grosmont Piloting History The Grosmont Formation in north-central Alberta is a dolomitized, karsted and fractured platform carbonate containing a massive bitumen accumulation. An excellent historical summary of various Grosmont pilots was recently provided by Alvarez et al.(1) Cyclic Steam Stimulation (CSS), steam drive and forward combustion were all attempted in the Grosmont during the '70s and '80s. CSS was the most widely and successfully piloted method. The best well, at 10A-5-88-19W4, recovered about 100,000 bbls of oil over 10 cycles, with a cumulative steam-oil ratio (CSOR) of about 6. Results of other tests were mixed, as were the operating procedures; most of these were based on horizontal flooding concepts. However, responses to well-executed CSS first cycles were reasonably similar at a number of widely-spaced wells. Notably, steam injectivity was generally sufficient so that a few hundred tonnes/day could be injected at pressures that were significantly below overburden pressure (ruling out geomechanical enhancement of permeability). A degree of pessimism, or at least great caution, has been expressed with respect to the supposed complexity of the reservoir, and hence, prospects for commercial recovery. In particular, it is often said that the reservoir is very heterogenous, and that this explains the historical failure of attempted steam drive and fire flood processes. Review of the Unocal Buffalo Creek and McLean scheme reports(2, 3) suggest that much of this originates in the interpretations of the contemporary operators, who largely explored conventional EOR concepts involving horizontal displacement. They expected to recover oil by means of horizontal, radial flow. When this failed, it was natural to assume that the problem lay in a failure to maintain the 'radial' part of the prescription, due to permeability heterogeneity. Figure 1 presents the performance of the Buffalo Creek 10A-5 CSS test in perspective with a contemporary test and two modern-day, commercially-optimized CSS wells (the data is publicly available from the Alberta Energy Resources Conservation Board). It can be seen that the Grosmont well had comparable performance to a Clearwater CSS test of the same vintage.
Field results from many heavy oil reservoirs in the Lindbergh and Frog Lake fields in northeastern Alberta suggest that primary recovery is mainly governed by the processes of sand production and foamy oil behaviour. Sand production leads to the creation of high porosity zones with increased permeability, while foamy oil generation provides the necessary support mechanism to sustain higher production rates. PanCanadian Petroleum Limited and Centre for Frontier Engineering Research (C-FER) conducted experimental and numerical studies to understand the various reservoir mechanisms contributing to the high primary production recovery observed in the Lindbergh and Frog Lake fields. Laboratory tests were conducted to study the foamy oil behaviour and evaluate its contribution to the enhanced primary production observed in the field. The numerical modelling included a series of idealized models developed and analyzed to determine the most probable shape of the sand-producing zones. The evaluation focussed on matching not only the observed oil production but also the observed sand volumes removed from the reservoir. The analysis from vertical well simulation was also extended to horizontal wells. The evaluation of heavy oil reservoir mechanisms for Lindbergh and Frog Lake fields is reported in two parts. Part I includes field testing and preliminary reservoir simulation based on the production data. Part II includes analytical and numerical studies for coupling the effects of sand and oil production, and laboratory testing of unconsolidated sand under foamy oil conditions. Introduction The observed primary oil production of many heavy oil reservoirs in the Lindbergh and Frog Lake fields in northeastern Alberta has been significantly higher than predicted by classical darcy flow models. PanCanadian Petroleum Limited (PanCanadian) and Centre for Frontier Engineering Research (C-FER) conducted experimental and numerical studies to understand the various reservoir mechanisms contributing to the observed high primary production recovery. This evaluation was conducted in two parts. Part I of the evaluation of heavy oil reservoir mechanisms for the Lindbergh and Frog Lake Fields was previously reported by the authors in Ref. (1). Part I included geological description of the Lindbergh and Frog Lake reservoirs, a summary of various field tests conducted in the area to evaluate recovery mechanisms and the results of reservoir simulation. P. 87
There is growing recognition and concern for the adverse impacts that ever increasing volumes of produced water have on oil production operations and reserves recovery. New technologies must be developed and successfully implemented to minimize the negative economic and environmental consequences of water production. Taking a novel approach in addressing these concerns, the Centre For Engineering Research Inc. has developed systems for downhole separation and same well injection of produced water. These systems have demonstrated significant potential to alleviate the high costs, production limitations and environmental risk associated with the handling of large volumes of produced water at surface. PanCanadian Petroleum Ltd. has deployed several of these systems in field trials at its Alliance operation in Canada which produces 38 API oil from a sandstone reservoir. The paper describes the candidate wells selected and the separation systems used in this application. Issues related to well conversions and system installation are reviewed and preliminary results from the field trials are presented. Introduction Produced water contributes to high operating expenses and is a major source of environmental concern for oil producers. Excessive water production also results in many wells and fields being suspended and abandoned, despite the fact that significant volumes of oil are still being produced. While it is not often reported, the water volumes produced in association with conventional oil are significant. In Canada, the oil industry produces almost six cubic meters of water, on average, for every cubic meter of oil produced. Some wells can be produced economically with water to oil ratios of over 100 with conventional production methods, but most wells currently become uneconomic at ratios as low as 10:1 or 20:1 due to the lifting and water handling costs. The Centre for Engineering Research Inc. (C-FER) initiated a feasibility study in 1991 to examine non-conventional means to reduce oil well lifting and water handling costs by reducing the volume of water produced to surface. This work resulted in the idea of combining hydrocyclone separators with conventional downhole oil field pumping systems to accomplish oil production, oil/water separation and simultaneous injection of the produced water in the same wellbore An ongoing joint industry project was subsequently organized by C-FER to further evaluate this concept through the development and testing of prototype separator systems. The project scope includes the development and field testing of prototype equipment for three downhole separation systems based on electric submersible pump (ESP), progressing cavity pump (PCP) and beam pump lift systems. The main objectives of the field tests are to demonstrate the operation and prove the economic benefits of the respective separation systems. The research and development project also addresses economic feasibility modeling, well recompletion design strategies and reservoir modeling to assess implementation of the technology in different fields. The many potential benefits associated with downhole oil/water separation and same well injection of produced water have been described previously by Peachey, 1991. This paper provides a description of this novel technology and presents the results from some of the initial field trials undertaken by PanCanadian Petroleum Ltd. with ESP oil/water separation systems. Downhole Separation Systems The downhole oil/water separation (AQWANOTM) systems under development by C-FER consist of a hydrocyclone separator coupled to a modified conventional pumping system. The hydrocyclone separator units employ standard liquid/liquid hydrocyclone liners (Colman, 1980, Schubert, 1992) which have been packaged for downhole service. P. 453
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