Slurrified Heavy Oil Reservoir Extraction (SHORE): A non-thermal, recovery method
- Richard James Smith (Imperial Oil Resources Ltd.) | Steven W Meier (ExxonMobil Research & Engineering Company) | Neal Leon Adair (ExxonMobil Upstream Research Co.) | Arnold P Kushnick (ExxonMobil Research & Engineering Company) | Sergio Adrian Leonardi (ExxonMobil Upstream Research Co.) | Eric Herbolzheimer (ExxonMobil Research & Engineering Company) | David P Yale (ExxonMobil Upstream Research Co.) | Jianlin Wang (ExxonMobil Upstream Research Co.)
- Document ID
- Society of Petroleum Engineers
- SPE Heavy Oil Conference-Canada, 11-13 June, Calgary, Alberta, Canada
- Publication Date
- Document Type
- Conference Paper
- 2013, Society of Petroleum Engineers
- 4.1.5 Processing Equipment, 5.5 Reservoir Simulation, 6.5.2 Water use, produced water discharge and disposal, 3.1.6 Gas Lift, 6.5.1 Air Emissions, 5.8.5 Oil Sand, Oil Shale, Bitumen, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 5.4.11 Cold Heavy Oil Production (CHOPS), 5.7.2 Recovery Factors, 5.4.6 Thermal Methods, 4.3.4 Scale, 2.4.3 Sand/Solids Control, 5.1.5 Geologic Modeling, 4.6 Natural Gas, 5.3.9 Steam Assisted Gravity Drainage, 4.1.2 Separation and Treating, 1.2.2 Geomechanics
- in-situ recovery, geomechanics, heavy oil, slurrified heavy oil reservoir extraction, non-thermal
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The oil sands of Canada are a rich resource whose extraction faces many challenges. The most common processes for recovering in situ resources (i.e. too deep to mine) involve heating the reservoir to reduce the heavy oil or bitumen viscosity to allow it to flow to wellbores where it can be produced. This paper presents an alternate concept for recovery of these resources that does not require heat to mobilize the bitumen and that is especially well suited to reservoirs that are too thin or too geologically complex for economic thermal recovery.
The process utilizes water injection to "condition?? a reservoir interval sufficiently to relieve the overburden stress on the oil sand and increase its porosity and permeability. Establishing a pressure gradient between a set of injector and producer wells allows the production of a bitumen-sand-water slurry as the pressure gradient established overcomes the friction holding the reservoir sand in place. This produced slurry is then processed at the surface to extract the bitumen and the cleaned tailings are re-injected back into the reservoir to aid in the sweep of the in situ sand, support the overburden, and dispose of the tails.
We have developed a first principles numerical model of the process that fully accounts for fluid flow and sand flow under reservoir conditions to simulate and understand the process. We have also developed a large scale (2 meter diameter sand pack) laboratory system to demonstrate the technical feasibility of the process under reservoir conditions.
The technology is still in the early stages of development, but the laboratory and numerical modeling efforts demonstrate promising technical potential of the process at a field-scale. The ability of the process to work in thinner and more geologically complex reservoirs than other in situ processes, and with lower CO2 and surface footprints than thermal and mining processes, could make this an attractive alternative recovery process for shallow to intermediate depth, in situ bitumen resources.
The Canadian oil sands are a rich resource whose recovery is challenged by the high and ultra-high viscosity of the heavy oil and bitumen trapped within the generally unconsolidated sand matrix of these reservoirs. Steam processes have dominated the in situ recovery of this resource (Lui and Stark, 2012; Fair et al., 2008; Saltuklaroglu et al., 2000; Butler, 1994) but steam-solvent and solvent only processes are currently being field tested (Boone et al., 2011; Lim et al., 1996). Although the shallow and young fluvial, esturine, and near shore environments of deposition lead to generally high permeability (1-10D), unconsolidated sand reservoirs, they also present challenges of a high degree of geologic variability and significant resources trapped in thin (<10-20m) pay sequences. Steam processes, especially low pressure process like SAGD, are challenged by both a high degree of geologic heterogeneity and thin pay zones. Although the cost of natural gas is currently low, increasing regulatory concern with CO2 emissions and the potential long term cost of natural gas could challenge the regulatory and economic attractiveness of steam processes in the long run. As such, development of a non-thermal, in situ recovery process that is more effective and economic in thin and/or more heterogeneous bitumen reservoirs could significantly expand the recoverable bitumen resources of the oil sands.
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